Hydrocracking process and system including removal of heavy poly nuclear aromatics from hydrocracker bottoms by coking

ABSTRACT

Hydrocracker bottoms fractions are treated to remove HPNA compounds and/or HPNA precursor compounds and produce a reduced-HPNA stream effective for recycle, in a configuration of a single-stage hydrocracking reactor, series-flow once through hydrocracking operation, or two-stage hydrocracking operation. The hydrocracker bottoms fractions are subjected to thermal cracking and HPNA compounds are removed with the coke phase.

RELATED APPLICATIONS

Not applicable.

BACKGROUND OF THE INVENTION Field of the Invention

The present invention relates to hydrocracking processes, and inparticular to hydrocracking processes including removal of heavy polynuclear aromatics from recycle streams using thermal cracking.

Description of Related Art

Hydrocracking processes are used commercially in a large number ofpetroleum refineries. They are used to process a variety of feedsboiling within the range of about 370-520° C. in conventionalhydrocracking units and boiling at 520° C. and above in residuehydrocracking units. In general, hydrocracking processes split themolecules of the feed into smaller, i.e., lighter, molecules havinghigher average volatility and economic value. Additionally,hydrocracking processes typically improve the quality of the hydrocarbonfeedstock by increasing the hydrogen-to-carbon ratio and by removingorganosulfur and organonitrogen compounds. The significant economicbenefit derived from hydrocracking processes has resulted in substantialdevelopment of process improvements and more active catalysts.

In addition to sulfur-containing and nitrogen-containing compounds, atypical hydrocracking feedstream, such as vacuum gas oil (VGO), containsa small amount of poly nuclear aromatic (PNA) compounds, i.e., thosecontaining less than seven fused aromatic rings. As the feedstream issubjected to hydroprocessing at elevated temperature and pressure, heavypoly nuclear aromatic (HPNA) compounds, i.e., those containing seven ormore fused benzene rings, tend to form and are present in highconcentration in the unconverted hydrocracker bottoms.

Heavy feedstreams such as demetallized oil (DMO) or deasphalted oil(DAO) have much higher concentrations of N, S and PNA compounds than VGOfeedstreams. These impurities can lower the overall efficiency ofhydrocracking units by requiring higher operating temperature, higherhydrogen partial pressure or additional reactor/catalyst volume. Inaddition, high concentrations of impurities can accelerate catalystdeactivation.

Three major hydrocracking process schemes include single-stage oncethrough hydrocracking, series-flow hydrocracking with or withoutrecycle, and two-stage recycle hydrocracking. Single-stage once throughhydrocracking is the simplest of the hydrocracker configurations andtypically occurs at operating conditions that are more severe thanhydrotreating processes, and less severe than conventional full-pressurehydrocracking processes. It uses one or more reactors for both thetreating steps and the cracking reaction, so the catalyst must becapable of both hydrotreating and hydrocracking. This configuration iscost effective, but typically results in relatively low product yields(for example, a maximum conversion rate of about 60%). Single-stagehydrocracking is often designed to maximize mid-distillate yield oversingle or dual catalyst systems. Dual catalyst systems can be used in astacked-bed configuration or in two different reactors. The effluentsare passed to a fractionator column to separate the H₂S, NH₃, lightgases (C₁-C₄), naphtha and diesel products boiling in the temperaturerange of 36−370° C. The hydrocarbons boiling above 370° C. are typicallyunconverted bottoms that, in single stage systems, are passed to otherrefinery operations.

Series-flow hydrocracking with or without recycle is one of the mostcommonly used configurations. It uses one reactor (containing bothtreating and cracking catalysts) or two or more reactors for bothtreating and cracking reaction steps. In a series-flow configuration theentire hydrocracked product stream from the first reaction zone,including light gases (typically C₁-C₄, H₂S, NH₃) and all remaininghydrocarbons, are sent to the second reaction zone. Unconverted bottomsfrom the fractionator column are recycled back into the first reactorfor further cracking. This configuration converts heavy crude oilfractions, i.e., vacuum gas oil, into light products and has thepotential to maximize the yield of naphtha, jet fuel, or diesel,depending on the recycle cut point used in the distillation section.

Two-stage recycle hydrocracking uses two reactors and unconvertedbottoms from the fractionation column are passed to the second reactorfor further cracking. Since the first reactor accomplishes bothhydrotreating and hydrocracking, the feed to second reactor is virtuallyfree of ammonia and hydrogen sulfide. This permits the use ofhigh-performance zeolite catalysts which are susceptible to poisoning byS or N compounds.

Typical hydrocracking feedstocks are vacuum gas oils boiling in thenominal range of 370-565° C. Heavier oil feedstreams such as DMO or DAO,alone or blended with vacuum gas oil, can be processed in ahydrocracking unit. For instance, a typical hydrocracking unit processesvacuum gas oils that contain from 10-25V % of DMO or DAO for optimumoperation. A 100V % DMO or DAO feed can also be processed, typicallyunder more severe conditions, since the DMO or DAO stream containssignificantly more N compounds (2,000 ppmw vs. 1,000 ppmw) and a highermicro carbon residue (MCR) content than the VGO stream (10 W % vs. <1 W%).

DMO or DAO content in blended feedstocks to a hydrocracking unit canlower the overall efficiency of the unit by increasing operatingtemperature or reactor/catalyst volume for existing units, or byincreasing hydrogen partial pressure requirements or reactor/catalystvolume for grass-roots units. These impurities can also reduce thequality of the desired intermediate hydrocarbon products in thehydrocracking effluent. When DMO or DAO are processed in a hydrocracker,further processing of hydrocracking reactor effluents may be required tomeet the refinery fuel specifications, depending upon the refineryconfiguration. When the hydrocracking unit is operating in its desiredmode, that is to say, discharging a high quality effluent productstream, its effluent can be utilized in blending and to producegasoline, kerosene and diesel fuel to meet established fuelspecifications.

In addition, formation of HPNA compounds is an undesirable side reactionthat occurs in recycle hydrocrackers. The HPNA molecules form bydehydrogenation of larger hydro-aromatic molecules or cyclization ofside chains onto existing HPNA molecules followed by dehydrogenation,which is favored as the reaction temperature increases. HPNA formationdepends on many known factors including the type of feedstock, catalystselection, process configuration, and operating conditions. Since HPNAmolecules accumulate in the recycle system and lead to equipmentfouling, HPNA formation must be controlled in the hydrocracking process.

The rate of formation of the various HPNA compounds increases withhigher conversion and heavier feedstocks. The fouling of equipment maynot be apparent until large amounts of HPNA accumulate in the recycleliquid loop. The problem of HPNA formation is of universal concern torefiners and various removal methods have been developed by refineryoperators to reduce its impact.

Conventional methods to separate or treat heavy poly-nuclear aromaticsformed in the hydrocracking process include adsorption, hydrogenation,extraction, solvent deasphalting and purging, or “bleeding” a portion ofthe recycle stream from the system to reduce the build-up of HPNAcompounds and cracking or utilizing the bleed stream elsewhere in therefinery. The hydrocracker bottoms are sometimes treated in separateunits to eliminate the HPNA molecules and recycle HPNA-free bottoms backto the hydrocracking reactor.

As noted above, one alternative when operating the hydrocracking unit inthe recycle mode is to purge a certain amount of the recycle liquid toreduce the concentration of HPNA that is introduced with the fresh feed,although purging reduces the conversion rate to below 100%. Anothersolution to the build-up problem is to eliminate the HPNAs by passingthem to a special purpose vacuum column which effectively fractionates98-99% of the recycle stream leaving most of the HPNAs at the bottom ofthe column for rejection from the system as fractionator bottoms. Thisalternative incurs the additional capital cost and operating expenses ofa dedicated fractionation column.

The problem therefore exists of providing a process for removing HPNAcompounds from the hydrocracker bottoms fraction from a hydrocrackingzone fractionator that is more efficient and cost effective than theknown processes.

SUMMARY OF THE INVENTION

Hydrocracker bottoms fractions are treated by coking operations toreduce or eliminate HPNA compounds and/or HPNA precursor compounds, andproduce a reduced-HPNA thermally cracked hydrocarbon products fractioneffective for recycle, in a configuration of a single-stagehydrocracking reactor, series-flow once through hydrocracking operation,or two-stage hydrocracking operation. Hydrocracker bottoms, alone or ina combination with an additional feedstock, are subjected to thermalcracking in a coking zone. All or a portion of the thermally crackedhydrocarbon products obtained from the coking zone are recycled withinthe integrated hydrocracking operation. The resulting coke contains HPNAcompounds and/or HPNA precursor compounds from the hydrocracker bottomsfraction.

The above methods for separation of HPNA and/or HPNA precursor compoundsby thermal cracking can be integrated in a hydrocracking operation usinga single reactor or plural reactors in a “once-through” configuration.Accordingly, in certain embodiments a hydrocracking process for treatinga heavy hydrocarbon feedstream which contains undesirednitrogen-containing compounds and poly-nuclear aromatic compounds isprovided that comprises subjecting the hydrocarbon feedstream to one ormore hydrocracking stages to produce a hydrocracked effluent. Thehydrocracked effluent is fractioned to recover hydrocracked products anda hydrocracked bottoms fraction containing HPNA and/or HPNA precursorcompounds. The hydrocracked bottoms fraction is subjected to thermalcracking in a coking zone, and all or a portion of the thermally crackedhydrocarbon products obtained from the coking zone is recycled.

In additional embodiments, the above methods for separation of HPNAand/or HPNA precursor compounds by thermal cracking can be integrated ina two-stage hydrocracking configuration. Accordingly, in certainembodiments, a hydrocracking process for treating a heavy hydrocarbonfeedstream which contains undesired nitrogen-containing compounds andpoly-nuclear aromatic compounds is provided that comprises subjectingthe hydrocarbon feedstream to one or more first hydrocracking stages toproduce a first stage effluent. The first stage effluent is fractionedto recover hydrocracked products and a hydrocracked bottoms fractioncontaining HPNA and/or HPNA precursor compounds. The hydrocrackedbottoms fraction is subjected to thermal cracking in a coking zone, andall or a portion of the thermally cracked hydrocarbon products obtainedfrom the coking zone is passed to a second hydrocracking stage.

In certain embodiments, a process for removal of HPNA compounds and/orHPNA precursor compounds from a hydrocracked bottoms fraction prior torecycling within a hydrocracking operation comprises: subjecting thehydrocracked bottoms fraction to thermal cracking to shift HPNA and/orHPNA precursor compounds to a coke phase and to produce thermallycracked hydrocarbon products, and recycling all or a portion of thethermally cracked hydrocarbon products within the hydrocrackingoperation. In certain embodiments, two stage hydrocracking processcomprises subjecting a hydrocarbon stream to a first hydrocracking stageto produce a first hydrocracked effluent; fractionating the firsthydrocracked effluent to recover one or more hydrocracked productfractions and a bottoms fraction corresponding to the hydrocrackedbottoms fraction of in the above process for removal of HPNA; whereinrecycling all or a portion of the thermally cracked hydrocarbon productscomprises passing all or a portion of the thermally cracked hydrocarbonproducts to a second hydrocracking stage to produce a secondhydrocracked effluent; and optionally wherein the second hydrocrackedeffluent is fractionated with the first hydrocracked effluent. Incertain embodiments, a hydrocracking process comprising subjecting ahydrocarbon stream to one or more hydrocracking stages to produce ahydrocracked effluent; fractionating the hydrocracked effluent torecover one or more hydrocracked product fractions and a hydrocrackedbottoms fraction corresponding to the hydrocracked bottoms fraction ofin the above process for removal of HPNA; and wherein recycling all or aportion of the thermally cracked hydrocarbon products within thehydrocracking operation comprises recycling all or a portion of thethermally cracked hydrocarbon products to at least one of the one ormore hydrocracking stages. In certain embodiments, the thermal crackingprocess is delayed coking. In certain embodiments, the thermal crackingprocess is fluid coking. In certain embodiments, the coking processintegrates adsorbent material and/or heterogeneous catalyst to enhanceremoval of HPNA and/or HPNA precursor compounds. In certain embodimentsthe process further passing an additional feed to the same thermalcracking process as the hydrocracked bottoms fraction.

In certain embodiments, a system for removal of HPNA compounds and/orHPNA precursor compounds from a hydrocracked bottoms fraction isprovided comprising a coking zone having one or more inlets in fluidcommunication with a hydrocracked bottoms outlet of a hydrocrackingfractionating zone, and one or more outlets for discharging thermallycracked hydrocarbon products. The one or more outlets for dischargingthermally cracked hydrocarbon products are in fluid communication with ahydrocracking operation as a bottoms recycle stream. The coking zonetypically further comprised apparatus or sub-systems for recovery andhandling of coke from the coking zone. In certain embodiments, a twostage hydrocracking system comprises a first hydrocracking reaction zonehaving one or more inlets in fluid communication with a source of aninitial feedstock, and one or more outlets for discharging a firsthydrocracked effluent stream; a fractionating zone having one or moreinlets in fluid communication with the outlet(s) for discharging thefirst hydrocracked effluent stream, one or more outlets discharging ahydrocracked product fractions, and one or more outlets discharging ahydrocracked bottoms fraction in fluid communication with the HPNAseparation zone as above; a second hydrocracking reaction zone havingone or more inlets in fluid communication with the outlet(s) fordischarging the HPNA-reduced hydrocracked bottoms portion of the HPNAseparation zone as above, and one or more outlets discharging a secondhydrocracked effluent stream; and optionally wherein the outlet(s) fordischarging the second hydrocracked effluent is in fluid communicationwith the fractioning zone. In certain embodiments, a hydrocrackingsystem comprises a hydrocracking reaction zone having one or more inletsin fluid communication with a source of an initial feedstock and is influid communication with the HPNA-reduced hydrocracked bottoms portionfrom the outlet(s) of the HPNA separation zone as above, and one or moreoutlets discharging an effluent stream; and a fractionating zone havingone or more inlets in fluid communication with the outlet(s) fordischarging the effluent stream, one or more outlets discharging ahydrocracked product fractions, and one or more outlets discharging ahydrocracked bottoms fraction in fluid communication with the inlet(s)of the HPNA separation zone as above. In certain embodiments, the HPNAseparation zone includes a contacting and/or mixing zone upstream of thesulfonation reaction zone. In certain embodiments, the HPNA separationzone is also in fluid communication with a source of additional feed.

Still other aspects, embodiments, and advantages of these exemplaryaspects and embodiments, are discussed in detail below. Moreover, it isto be understood that both the foregoing information and the followingdetailed description are merely illustrative examples of various aspectsand embodiments, and are intended to provide an overview or frameworkfor understanding the nature and character of the claimed aspects andembodiments. The accompanying drawings are included to provideillustration and a further understanding of the various aspects andembodiments, and are incorporated in and constitute a part of thisspecification. The drawings, together with the remainder of thespecification, serve to explain principles and operations of thedescribed and claimed aspects and embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further detail below and withreference to the attached drawings in which the same or similar elementsare referred to by the same number, and where:

FIG. 1 is a process flow diagram of an embodiment of an integratedhydrocracking unit operation;

FIG. 2 is a process flow diagram of an integrated series-flowhydrocracking system;

FIG. 3 is a process flow diagram of an integrated two-stagehydrocracking system with recycle;

FIG. 4 is a process flow diagram of a hydrocracking operation integratedwith a coking reaction and separation zone operating as a delayed coker;

FIG. 5 is a process flow diagram of a hydrocracking operation integratedwith a coking reaction and separation zone operating as a fluid coker;

FIG. 6 is a process flow diagram of a hydrocracking operation integratedwith a coking reaction and separation zone operating with additionalmaterial to assist coking; and

FIG. 7 is a plot of hydrocracker bottoms content in a delayed cokeragainst the coke yield.

DETAILED DESCRIPTION OF THE INVENTION

Integrated processes and systems are provided for to improve efficiencyof hydrocracking operations, by removing HPNA and/or HPNA precursorcompounds prior to recycling within a hydrocracking operation. Theprocesses and systems herein are effective for different types ofhydrocracking operations, and are also effective for a wide range ofinitial hydrocracking feedstocks obtained from various sources, such asone or more of straight run vacuum gas oil, treated vacuum gas oil,demetallized oil from solvent demetallizing operations, deasphalted oilfrom solvent deasphalting operations, coker gas oils from cokeroperations separate from the integrated coking zone, cycle oils fromfluid catalytic cracking operations (including heavy cycle oil), andvisbroken oils from visbreaking operations. The feedstream generally hasa boiling point range within about 350-800, 350-700, 350-600 or 350-565°C.

As used herein, “HPNA compounds” and the shorthand expression “HPNA(s)”refers to fused polycyclic aromatic compounds having double bondequivalence (DBE) values of 19 and above, or having 7 or more rings, forexample, including but not limited to coronenes (C₂₄H₁₂), benzocoronenes(C₂₈H₁₄), dibenzocorones (C₃₂H₁₆) and ovalenes (C₃₂H₁₄). The aromaticstructure may have alkyl groups or naphthenic rings attached to it. Forinstance, coronene has 24 carbon atoms and 12 hydrogen atoms. Its doublebond equivalency (DBE) is 19. DBE is calculated based on the sum of thenumber double bonds and number of rings. For example, the DBE value forcoronene is 19 (7 rings+12 double bonds). Examples of HPNA compounds areshown in Table 1.

As used herein, “HPNA precursors” are poly nuclear compounds having lessthan 7 aromatic rings, for instance 2-7 or 3-7 aromatic rings.

As used herein, the term hydrocracking recycle stream is synonymous withthe terms hydrocracker bottoms, hydrocracked bottoms, hydrocrackerunconverted material and fractionator bottoms.

As used herein, the shorthand expressions “HPNAs/HPNA precursors,” “HPNAcompounds and HPNA precursor compounds,” “HPNAs and HPNA precursors,”and “HPNA compounds and/or HPNA precursor compounds” are usedinterchangeably and refer to a combination of HPNA compounds and HPNAprecursor compounds unless more narrowly defined in context.

TABLE 1 HPNAs Ring # Structure benzoperylene 6

coronene 7

methylcoronene 7

naphtheno- coronene 9

dibenzo- coronene 9

ovalene 10

Volume percent or “V %” refers to a relative at conditions of 1atmosphere pressure and 15° C.

The phrase “a major portion” with respect to a particular stream orplural streams, or content within a particular stream, means at leastabout 50 wt % and up to 100 wt %, or the same values of anotherspecified unit.

The phrase “a significant portion” with respect to a particular streamor plural streams, or content within a particular stream, means at leastabout 75 wt % and up to 100 wt %, or the same values of anotherspecified unit.

The phrase “a substantial portion” with respect to a particular streamor plural streams, or content within a particular stream, means at leastabout 90, 95, 98 or 99 wt % and up to 100 wt %, or the same values ofanother specified unit.

The phrase “a minor portion” with respect to a particular stream orplural streams, or content within a particular stream, means from about1, 2, 4 or 10 wt %, up to about 20, 30, 40 or 50 wt %, or the samevalues of another specified unit.

The term “naphtha” as used herein refers to hydrocarbons boiling in therange of about 20-220, 20-210, 20-200, 20-190, 20-180, 20-170, 32-220,32-210, 32-200, 32-190, 32-180, 32-170, 36-220, 36-210, 36-200, 36-190,36-180 or 36-170° C.

The term “light naphtha” as used herein refers to hydrocarbons boilingin the range of about 20-110, 20-100, 20-90, 20-88, 32-110, 32-100,32-90, 32-88, 36-110, 36-100, 36-90 or 36-88° C.

The term “heavy naphtha” as used herein refers to hydrocarbons boilingin the range of about 90-220, 90-210, 90-200, 90-190, 90-180, 90-170,93-220, 93-210, 93-200, 93-190, 93-180, 93-170, 100-220, 100-210,100-200, 100-190, 100-180, 100-170, 110-220, 110-210, 110-200, 110-190,110-180 or 110-170° C.

The term “middle distillates” as used herein relative to effluents fromthe atmospheric distillation unit or flash zone refers to hydrocarbonsboiling in the range of about 170-370, 170-360, 170-350, 170-340,170-320, 180-370, 180-360, 180-350, 180-340, 180-320, 190-370, 190-360,190-350, 190-340, 190-320, 200-370, 200-360, 200-350, 200-340, 200-320,210-370, 210-210, 210-350, 210-340, 210-320, 220-370, 220-220, 220-350,220-340 or 220-320° C.

The term “atmospheric residue” as used herein refers to the bottomhydrocarbons obtained from atmospheric distillation and having aninitial boiling point corresponding to the end point of the middledistillate range hydrocarbons, and having an end point based on thecharacteristics of the crude oil feed.

The term “vacuum gas oil” and its acronym “VGO” as used herein refer tohydrocarbons obtained from vacuum distillation, typically of atmosphericresidue, and having an initial boiling point in the range of about350-420° C. and an end boiling point in the range of about 510-565° C.,for instance hydrocarbons boiling in the range of about 350-565,350-540, 350-530, 350-510, 370-565, 370-550, 370-540, 370-530, 370-510,400-565, 400-550, 400-540, 400-530, 400-510, 420-565, 420-550, 420-540,420-530 or 420-510° C.

The term “vacuum residue” as used herein refers to the bottomhydrocarbons obtained from vacuum distillation and having an initialboiling point corresponding to the end point of the VGO rangehydrocarbons, and having an end point based on the characteristics ofthe crude oil feed.

The modifying term “straight run” is used herein having its well-knownmeaning, that is, describing fractions that are conventionally deriveddirectly from the distillation unit, optionally subjected to steamstripping, rather than being from another refinery treatment such ascoking, hydroprocessing, fluid catalytic cracking or steam cracking.

The term “unconverted oil,” also known as hydrocracker bottoms,hydrocracked bottoms, hydrocracker unconverted material and fractionatorbottoms, is used herein having its known meaning, and refers to a highlyparaffinic fraction obtained from a separation zone associated with ahydroprocessing reactor, and contains reduced N, S and Ni contentrelative to the reactor feed, and includes in certain embodimentshydrocarbons having an initial boiling point in the range of about340-370° C., for instance about 340, 360 or 370° C., and an end point inthe range of about 510-560° C., for instance about 540, 550, 560° C. orhigher depending on the characteristics of the feed to thehydroprocessing reactor, and hydroprocessing reactor design andconditions, for instance hydrocarbons boiling in the range of about340-560, 340-550, 340-540, 360-560, 360-550, 360-540, 370-560, 370-550,or 370-540° C. UCO is also known in the industry by other synonymsincluding “hydrowax.”

The term “coker gas oil” and its acronym “CGO” as used herein refer tohydrocarbons boiling above an end point of the middle distillate range,for instance having an initial boiling point in the range of about320-370° C., and an end boiling point in the range of about 510-565° C.,which are derived from thermal cracking operations in a coker unit, forinstance hydrocarbons boiling in the range of about 320-565, 320-540,320-510, 340-565, 340-540, 340-510, 370-565, 370-540, or 370-510° C.

The term “heavy coker gas oil” is used herein to refer to coker gas oilin the heavy range, for instance having an initial boiling point fromabout 375-425° C., for instance hydrocarbons boiling in the range ofabout 375-565, 375-540, 375-510, 400-565, 400-540, 400-510, 425-565,425-540, or 425-510° C.

The term “light coker gas oil” is used herein to refer to coker gas oilin the light range, for instance having an end boiling point from about375-425° C., for instance hydrocarbons boiling in the range of about320-425, 320-400, 320-375, 340-425, 340-375, 340-375, 370-425, 370-400,or 370-375° C.

The term “coker naphtha” is used herein to refer to hydrocarbons boilingin the naphtha range derived from thermal cracking operations in a cokerunit.

The term “coker middle distillates” is used herein to refer tohydrocarbons boiling in the middle distillate range derived from thermalcracking operations in a coker unit.

Hydrocracker bottoms fractions from a hydrocracking operation containingHPNA compounds and/or HPNA precursor compounds are subjected to thermalcracking, alone or in combination with an additional feedstock. Thehydrocracking operation can be in the configuration of a single reactorwith recycle, plural reactors in series flow with recycle, or two stagesof reactor with recycle. Thermally cracked hydrocarbon products havingreduced HPNA content relative to the hydrocracker bottoms fractions isused as a hydrocracking recycle stream in the hydrocracking operation.Resulting coke from the thermal cracking contains HPNA compounds and/orHPNA precursor compounds from the hydrocracker bottoms fraction.

The thermally cracked hydrocarbon products can include coker gas oil,coker middle distillates and coker naphtha; coker gas oil, coker middledistillates and coker heavy naphtha; coker gas oil and coker middledistillates; coker gas oil and heavy coker middle distillates; coker gasoil; or heavy coker gas oil. In certain embodiments, one or more cokerdistillate streams are also provided which contains coker distillateproducts outside of the range of the thermally cracked hydrocarbonproducts that are recycled to the hydrocracking operation.

Operation of the integrated system and process herein overcomesconventional problems associated with upgrading of hydrocracker bottomcontaining HPNA compounds and/or HPNA precursor compounds that wereformed in the reaction zones, since they are substantially removed fromthe system through the coking zone by cracking and forming additionaldistillate products. Those HPNA compounds and/or HPNA precursorcompounds that are not cracked form part of the coke by-product. Forinstance, in the coking zone, 90 W %, 95 W %, 99 W %, 99.9 W % of HPNAcompounds and/or 50 W %, 75 W %, 90 W %, 95.0 W % HPNA precursorcompounds is removed and passed to the coke phase.

FIG. 1 is a process flow diagram of an embodiment of a hydrocrackingunit operation integrated with a coking reaction and separation zone. Ahydrocracking system 100 operates as single stage hydrocracking unitwith recycle. In general, the hydrocracking system 100 includes ahydrocracking reaction zone 106 and a fractionating zone 110, which areintegrated with a coking reaction and separation zone 120. Reaction zone106 generally includes one or more inlets in fluid communication with asource of initial feedstock 102, a source of hydrogen gas 104, and thecoking reaction and separation zone 120 to receive a recycle streamcomprising all or a portion of a thermally cracked hydrocarbon productsstream 122. Reaction zone 106 includes an effective reactorconfiguration with the requisite reaction vessel(s), feed heaters, heatexchangers, hot and/or cold separators, product fractionators,strippers, and/or other units to process, and operates with effectivecatalyst(s) and under effective operating conditions to carry out thedesired degree of treatment and conversion of the feed. One or moreoutlets of reaction zone 106 that discharge effluent stream 108 are influid communication with one or more inlets of the fractionating zone110. In certain embodiments (not shown), effluents from thehydrocracking reaction vessels are cooled in an exchanger and sent to ahigh pressure cold or hot separator. The fractionating zone 110generally includes one or more outlets for discharging a distillatefraction 114 containing cracked naphtha and cracked middledistillate/diesel products; and one or more outlets for discharging ahydrocracker bottoms fraction 116 containing unconverted oil. In certainembodiments, the fractionation zone 110 includes one or more outlets fordischarging gases, stream 112, typically H₂, H₂S, NH₃, and lighthydrocarbons (C₁-C₄).

The hydrocracker bottoms fraction 116 outlet is in fluid communicationwith one or more inlets of the coking reaction and separation zone 120.In certain embodiments one or more optional additional feeds, stream148, are in fluid communication with one or more inlets of the cokingreaction and separation zone 120. As shown in the integration withsystem 100, the coking reaction and separation zone 120 generallyincludes one or more outlets for discharging the thermally crackedhydrocarbon products stream 122, and a coke discharge, schematicallyshown as line 124, within which HPNA compounds and/or HPNA precursorcompounds from the hydrocracker bottoms are contained. In certainembodiments the coking reaction and separation zone 120 contains one ormore outlets for discharging thermally cracked distillates stream 152(shown in dashed lines) which can include coker naphtha, coker middledistillates and/or light coker gas oil. The outlet discharging thethermally cracked hydrocarbon products stream 122 is in fluidcommunication with one or more inlets of reaction zone 106 for recycleof all or a portion of the stream. In certain embodiments, a bleedstream 118 is drawn from bottoms 116 upstream of the coking reaction andseparation zone 120. In additional embodiments, a bleed stream 126 isdrawn from the thermally cracked hydrocarbon products stream 122downstream of the coking reaction and separation zone 120, in additionto or instead of bleed stream 118. Either or both of these bleed streamscontain unconverted oil that is hydrogen-rich and therefore can beeffectively integrated with certain fuel oil pools, or serve as feed tofluidized catalytic cracking or steam cracking processes (not shown).

In operation of the system 100/120, a feedstock stream 102 and ahydrogen stream 104 are charged to the reaction zone 106. Hydrogenstream 104 contains an effective quantity of hydrogen to support therequisite degree of hydrocracking, feed type, and other factors, and canbe any combination including make-up hydrogen, recycle hydrogen fromoptional gas separation subsystems (not shown) between reaction zone 106and fractionating zone 110, derived from fractionator gas stream 112,and/or derived from coker gas products from coking reaction andseparation zone 120. Reaction zone 106 operates under effectiveconditions for production of a reaction effluent stream 108 whichcontains converted, partially converted and unconverted hydrocarbons,including HPNA and/or HPNA precursor compounds formed in the reactionzone 106. One or more high pressure and low pressure separation stagescan be integrated as is known to recover recycle hydrogen between thereaction zone 106 and fractionating zone 110. For example, effluentsfrom the hydrocracking reaction vessel are cooled in an exchanger andsent to a high pressure cold or hot separator. Separator tops arecleaned in an amine unit and the resulting hydrogen rich gas stream ispassed to a recycling compressor to be used as a recycle gas in thehydrocracking reaction vessel. Separator bottoms from the high pressureseparator, which are in a substantially liquid phase, are cooled andthen introduced to a low pressure cold separator. Remaining gasesincluding hydrogen, H₂S, NH₃ and any light hydrocarbons, which caninclude C₁-C₄ hydrocarbons, can be conventionally purged from the lowpressure cold separator and sent for further processing, such as flareprocessing or fuel gas processing. The liquid stream from the lowpressure cold separator is passed to the fractionating zone 110.

The reaction effluent stream 108 is passed to fractionating zone 110,generally to recover gas stream 112 and liquid products 114 and toseparate a bottoms fraction 116 containing HPNA compounds. Gas stream112, typically containing H₂, H₂S, NH₃, and light hydrocarbons (C₁-C₄),is discharged and recovered and can be further processed as is known inthe art, including for recovery of recycle hydrogen. In certainembodiments one or more gas streams are discharged from one or moreseparators between the reactor and the fractionator (not shown), and gasstream 112 can be optional from the fractionator. One or more crackedproduct streams 114 are discharged from appropriate outlets of thefractionator and can be further processed and/or blended in downstreamrefinery operations as gasoline, kerosene and/or diesel fuel products orintermediates, and/or other hydrocarbon mixtures that can be used toproduce petrochemical products. In certain embodiments (not shown),fractionating zone 110 can operate as one or more flash vessels toseparate heavy components at a suitable cut point, for example, a rangecorresponding to the upper temperature range of the desired productstream 114.

In certain embodiments, all, a major portion, a significant portion, ora substantial portion of the fractionator bottoms stream 116 derivedfrom the reaction effluent, containing HPNA compounds and/or HPNAprecursors formed in the reaction zone 106, is passed to the cokingreaction and separation zone 120 for thermal cracking. In certainembodiments a portion of the fractionator bottoms from the reactioneffluent is removed from the recycle loop as bleed stream 118. Bleedstream 118 can contain a suitable portion (V %) of the fractionatorbottoms 116, in certain embodiments about 0-10, 0-5, 0-3, 1-10, 1-5 or1-3. HPNA compounds and/or HPNA precursors in the hydrocracking effluentfractionator bottoms are retained in the coke phase in the cokingreaction and separation zone 120, and all or a portion of the thermallycracked hydrocarbon products stream 122 is recycled. In certainembodiments, instead of or in conjunction with bleed stream 118, aportion of the thermally cracked hydrocarbon products stream 122 isremoved from the recycle loop as bleed stream 126. Bleed stream 126 cancontain a suitable portion (V %) of the thermally cracked hydrocarbonproducts stream 122, in certain embodiments about 0-10, 0-5, 0-3, 1-10,1-5 or 1-3. A coke discharge 124 containing HPNA compounds is removedfrom the system. The coke contains solvent insoluble compounds, and inthe process herein HPNA and/or HPNA precursor compounds react with oneanother and dimerize or polymerize, forming HPNA compounds and/or largerHPNA compounds with a greater number of rings. These will becomeinsoluble become coke material. In certain embodiments, all, a majorportion, a significant portion, or a substantial portion of thethermally cracked hydrocarbon products stream 122 is recycled to thereaction zone 106. The stream 122 is obtained from the coking reactionand separation zone 120 and has a reduced concentration of HPNAcompounds relative to the hydrocracker bottoms fraction. In certainembodiments, a thermally cracked distillates stream 152 (shown in dashedlines) is discharged from the coking reaction and separation zone 120which can include coker naphtha, coker middle distillates and/or lightcoker gas oil.

In additional embodiments, one or more optional additional feeds, stream148 can be routed to the coking reaction and separation zone 120. Incertain embodiments the only feed to the coking reaction and separationzone 120 are derived from the fractionator bottoms 116.

Reaction zone 106 can contain one or more fixed-bed, ebullated-bed,slurry-bed, moving bed, continuous stirred tank (CSTR), or tubularreactors, in series and/or parallel arrangement. The reactor(s) aregenerally operated under conditions effective for the desired level oftreatment, degree of conversion, type of reactor, the feedcharacteristics, and the desired product slate. In certain embodimentsthe reactors operate at conversion levels (V % of feed that is recoveredabove the unconverted oil range) in the range of 30-90, 50-90, 60-90 or70-90. For instance, these conditions can include a reaction temperature(° C.) in the range of from about 300-500, 300-475, 300-450, 330-500,330-475 or 330-450; a reaction pressure (bars) in the range of fromabout 60-300, 60-200, 60-180, 100-300, 100-200, 100-180, 130-300,130-200 or 130-180; a hydrogen feed rate (standard liter per liter ofhydrocarbon feed (SL/L)) of up to about 2500, 2000 or 1500, in certainembodiments from about 800-2500, 800-2000, 800-1500, 1000-2500,1000-2000 or 1000-1500; and a feed rate liquid hourly space velocity(h⁻¹) in the range of from about 0.1-10, 0.1-5, 0.1-2, 0.25-10, 0.25-5,0.25-2, 0.5-10, 0.5-5 or 0.5-2. Effective catalysts used in reactionzone 106 possess hydrotreating functionality (hydrodesulfurization,hydrodenitrification and/or hydrodemetallization) and hydrocrackingfunctionality. Hydrodesulfurization, hydrodenitrification and/orhydrodemetallization is carried out to remove S, N and othercontaminants, and conversion of feedstocks occurs by cracking intolighter fractions, for instance, in certain embodiments at least about30 V % conversion.

FIG. 2 is a process flow diagram of another embodiment of ahydrocracking unit operation integrated with a coking reaction andseparation zone. A hydrocracking system 200 operates as series-flowhydrocracking system with recycle to the first reactor zone, the secondrector zone, or both the first and second reactor zones. In general, thehydrocracking system 200 includes a first reaction zone 228, a secondreaction zone 232 and a fractionating zone 210, which are integratedwith a coking reaction and separation zone 220. The first reaction zone228 generally includes one or more inlets in fluid communication with asource of initial feedstock 202, a source of hydrogen gas 204, andoptionally the coking reaction and separation zone 220 to receive arecycle stream comprising all or a portion of a thermally crackedhydrocarbon products stream 222, shown in dashed lines as stream 222 b.The first reaction zone 228 includes an effective reactor configurationwith the requisite reaction vessel(s), feed heaters, heat exchangers,hot and/or cold separators, product fractionators, strippers, and/orother units to process, and operates with effective catalyst(s) andunder effective operating conditions to carry out the desired degree oftreatment and conversion of the feed. One or more outlets of the firstreaction zone 228 that discharge effluent stream 230 is in fluidcommunication with one or more inlets of the second reaction zone 232.In certain embodiments, the effluents 230 are passed to the secondreaction zone 232 without separation of any excess hydrogen and lightgases. In optional embodiments, one or more high pressure and lowpressure separation stages are provided between the first and secondreaction zones 228, 232 for recovery of recycle hydrogen (not shown).The second reaction zone 232 generally includes one or more inlets influid communication with one or more outlets of the first reaction zone228, optionally a source of additional hydrogen gas 205 and optionallythe coking reaction and separation zone 220 to receive a recycle streamcomprising all or a portion of the thermally cracked hydrocarbonproducts stream 222, shown in dashed lines as stream 222 a. The secondreaction zone 232 includes an effective reactor configuration with therequisite reaction vessel(s), feed heaters, heat exchangers, hot and/orcold separators, product fractionators, strippers, and/or other units toprocess, and operates with effective catalyst(s) and under effectiveoperating conditions to carry out the desired degree of additionalconversion of the feed. One or more outlets of the second reaction zone232 that discharge effluent stream 234 is in fluid communication withone or more inlets of the fractionating zone 210 (optionally having oneor more high pressure and low pressure separation stages therebetweenfor recovery of recycle hydrogen, not shown). The fractionating zone 210generally includes one or more outlets for discharging a distillatefraction 214 containing cracked naphtha and cracked middledistillate/diesel products and one or more outlets for discharging abottoms fraction 216 containing unconverted oil. In certain embodiments,the fractionation zone 210 includes one or more outlets for discharginggases, stream 212, typically H₂, H₂S, NH₃, and light hydrocarbons(C₁-C₄).

The bottoms fraction 216 outlet is in fluid communication with one ormore inlets of the coking reaction and separation zone 220. In certainembodiments one or more optional additional feeds, stream 248, are influid communication with one or more inlets of the coking reaction andseparation zone 220. As shown in the integration with system 200, thecoking reaction and separation zone 220 generally includes one or moreoutlets for discharging the thermally cracked hydrocarbon productsstream 222, and a coke discharge, schematically shown as line 224,within which HPNA compounds and/or HPNA precursor compounds from thehydrocracker bottoms are contained. In certain embodiments the cokingreaction and separation zone 220 contains one or more outlets fordischarging thermally cracked distillates stream 252 (shown in dashedlines) which can include coker naphtha, coker middle distillates and/orlight coker gas oil. The outlet discharging the thermally crackedhydrocarbon products stream 222 is in fluid communication with one ormore inlets of reaction zone 228 and/or 232 for recycle of all or aportion of the stream. In certain embodiments, a bleed stream 218 isdrawn from bottoms 216 upstream of the coking reaction and separationzone 220. In additional embodiments, a bleed stream 226 is drawn fromthe thermally cracked hydrocarbon products stream 222 downstream of thecoking reaction and separation zone 220, in addition to or instead ofbleed stream 218. Either or both of these bleed streams containunconverted oil that is hydrogen-rich and therefore can be effectivelyintegrated with certain fuel oil pools, or serve as feed to fluidizedcatalytic cracking or steam cracking processes (not shown).

In operation of the system 200/220, a feedstock stream 202 and ahydrogen stream 204 are charged to the first reaction zone 228. Hydrogenstream 204 includes an effective quantity of hydrogen to support therequisite degree of hydrocracking, feed type, and other factors, and canbe any combination including make-up hydrogen, recycle hydrogen fromoptional gas separation subsystems (not shown) between reaction zones228 and 232, recycle hydrogen from optional gas separation subsystems(not shown) between reaction zone 232 and fractionator 210, derived fromfractionator gas stream 212, and/or derived from coker gas products fromcoking reaction and separation zone 220. The first reaction zone 228operates under effective conditions for production of a reactioneffluent stream 230 (optionally after one or more high pressure and lowpressure separation stages to recover recycle hydrogen) which is passedto the second reaction zone 232, optionally along with an additionalhydrogen stream 205. The second reaction zone 232 operates underconditions effective for production of the reaction effluent stream 234,which contains converted, partially converted and unconvertedhydrocarbons. The reaction effluent stream further includes HPNAcompounds that were formed in the reaction zones 228 and/or 232. One ormore high pressure and low pressure separation stages can be integratedas is known to recover recycle hydrogen between the reaction zone 228and the reaction zone 232, and/or between the reaction zone 232 andfractionating zone 210. For example, effluents from the hydrocrackingreaction zones 228 and/or 232 are cooled in an exchanger and sent to ahigh pressure cold or hot separator. Separator tops are cleaned in anamine unit and the resulting hydrogen rich gas stream is passed to arecycling compressor to be used as a recycle gas in the hydrocrackingreaction vessel. Separator bottoms from the high pressure separator,which are in a substantially liquid phase, are cooled and thenintroduced to a low pressure cold separator. Remaining gases includinghydrogen, H₂S, NH₃ and any light hydrocarbons, which can include C₁-C₄hydrocarbons, can be conventionally purged from the low pressure coldseparator and sent for further processing, such as flare processing orfuel gas processing. The liquid stream from the low pressure coldseparator is passed to the next stage, that is, the second reactor 232or the fractionating zone 210.

The reaction effluent stream 234 is passed to the fractionation zone210, generally to recover gas stream 212 and liquid products 214 and toseparate a bottoms fraction 216 containing HPNA compounds. Gas stream212, typically containing H₂, H₂S, NH₃, and light hydrocarbons (C₁-C₄),is discharged and recovered and can be further processed as is known inthe art, including for recovery of recycle hydrogen. In certainembodiments one or more gas streams are discharged from one or moreseparators between the reactors, or between the reactor and thefractionator (not shown), and gas stream 212 can be optional from thefractionator. One or more cracked product streams 214 are dischargedfrom appropriate outlets of the fractionator and can be furtherprocessed and/or blended in downstream refinery operations as gasoline,kerosene and/or diesel fuel products or intermediates, and/or otherhydrocarbon mixtures that can be used to produce petrochemical products.In certain embodiments (not shown), fractionating zone 210 can operateas one or more flash vessels to separate heavy components at a suitablecut point, for example, a range corresponding to the upper temperaturerange of the desired product stream 214.

In certain embodiments, all, a major portion, a significant portion, ora substantial portion of the fractionator bottoms stream 216, containingHPNA compounds and/or HPNA precursors formed in the reaction zones, ispassed to the coking reaction and separation zone 220 for thermalcracking. In certain embodiments a portion of the fractionator bottomsfrom the reaction effluent is removed from the recycle loop as bleedstream 218. Bleed stream 218 can contain a suitable portion (V %) of thefractionator bottoms 216, in certain embodiments about 0-10, 0-5, 0-3,1-10, 1-5 or 1-3. HPNA compounds and/or HPNA precursors in thehydrocracking effluent fractionator bottoms are retained in the cokephase in the coking reaction and separation zone 220, and all or aportion of the thermally cracked hydrocarbon products stream 222 isrecycled. A coke discharge 224 containing HPNA compounds is removed fromthe system. In certain embodiments, instead of or in conjunction withbleed stream 218, a portion of the thermally cracked hydrocarbonproducts stream 222 is removed from the recycle loop as bleed stream226. Bleed stream 226 can contain a suitable portion (V %) of thethermally cracked hydrocarbon products stream 222, in certainembodiments about 0-10, 0-5, 0-3, 1-10, 1-5 or 1-3. In certainembodiments, all or a portion of the thermally cracked hydrocarbonproducts stream 222 is recycled to the second reaction zone 232 asstream 222 a, the first reaction zone 228 as stream 222 b, or both thefirst and second reaction zones 228 and 232. For instance, stream 222 bcomprises (V %) 0-100, 0-80 or 0-50 relative to stream 222 that isrecycled to zone 228, and stream 222 a comprises 0-100, 0-80 or 0-50relative to stream 222 that is recycled to zone 232. In certainembodiments, all, a major portion, a significant portion, or asubstantial portion of the thermally cracked hydrocarbon products stream222 is recycled to the first reaction zone 228 as stream 222 b. Thestream 222 is obtained from the coking reaction and separation zone 220and has a reduced concentration of HPNA compounds relative to thehydrocracker bottoms fraction. In certain embodiments, a thermallycracked distillates stream 252 (shown in dashed lines) is dischargedfrom the coking reaction and separation zone 220 which can include cokernaphtha, coker middle distillates and/or light coker gas oil.

In additional embodiments, one or more optional additional feeds, stream248 can be routed to the coking reaction and separation zone 220. Incertain embodiments the only feed to the coking reaction and separationzone 220 are derived from the fractionator bottoms 216.

The first reaction zone 228 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, CSTR, or tubular reactors, inseries and/or parallel arrangement. The reactor(s) are generallyoperated under conditions effective for the desired level of treatmentand degree of conversion in the first reaction zone 228, the particulartype of reactor, the feed characteristics, and the desired productslate. For instance, these conditions can include a reaction temperature(° C.) in the range of from about 300-500, 300-475, 300-450, 330-500,330-475 or 330-450; a reaction pressure (bars) in the range of fromabout 60-300, 60-200, 60-180, 100-300, 100-200, 100-180, 130-300,130-200 or 130-180; a hydrogen feed rate (SL/L) of up to about 2500,2000 or 1500, in certain embodiments from about 800-2500, 800-2000,800-1500, 1000-2500, 1000-2000 or 1000-1500; and a feed rate liquidhourly space velocity (h⁻¹) in the range of from about 0.1-10, 0.1-5,0.1-2, 0.25-10, 0.25-5, 0.25-2, 0.5-10, 0.5-5 or 0.5-2. The catalystused in the first reaction zone 228 can comprise those havinghydrotreating functionality, and in certain embodiments those havinghydrotreating and hydrocracking functionality. In embodiments in whichcatalysts used in first reaction zone 228 possess hydrotreatingfunctionality, including hydrodesulfurization, hydrodenitrificationand/or hydrodemetallization, the focus is removal of S, N and othercontaminants, with a limited degree of conversion (for instance in therange of 10-30 V %). In embodiments in which catalysts used in firstreaction zone 228 possess hydrotreating and hydrocracking functionality,a higher degree of conversion, generally above about 20 V %, occurs.

The second reaction zone 232 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, CSTR, or tubular reactors, inseries and/or parallel arrangement. The reactor(s) are generallyoperated under conditions effective for the desired degree ofconversion, particular type of reactor, the feed characteristics, andthe desired product slate. For instance, these conditions can include areaction temperature (° C.) in the range of from about 300-500; areaction pressure (bars) in the range of from about 60-300, 60-200,60-180, 100-300, 100-200, 100-180, 130-300, 130-200 or 130-180; ahydrogen feed rate (SL/L) of up to about 2500, 2000 or 1500, in certainembodiments from about 800-2500, 800-2000, 800-1500, 1000-2500,1000-2000 or 1000-1500; and a feed rate liquid hourly space velocity(h⁻¹) in the range of from about 0.1-10, 0.1-5, 0.1-2, 0.25-10, 0.25-5,0.25-2, 0.5-10, 0.5-5 or 0.5-2. The catalyst used in the second reactionzone 232 can comprise those having hydrocracking hydrodesulfurizationand hydrodenitrogenation functionality, and in certain embodiments thosehaving hydrocracking and hydrogenation functionality.

FIG. 3 is a process flow diagram of another embodiment of ahydrocracking unit operation integrated with a coking reaction andseparation zone. A hydrocracking system 300 operates as two-stagehydrocracking system with recycle. In general, the hydrocracking system300 includes a first reaction zone 336, a second reaction zone 340 and afractionating zone 310, which are integrated with a coking reaction andseparation zone 320. The first reaction zone 336 generally includes oneor more inlets in fluid communication with a source of initial feedstock302 and a source of hydrogen gas 304. The first reaction zone 336includes an effective reactor configuration with the requisite reactionvessel(s), feed heaters, heat exchangers, hot and/or cold separators,product fractionators, strippers, and/or other units to process, andoperates with effective catalyst(s) and under effective operatingconditions to carry out the desired degree of treatment and conversionof the feed. One or more outlets of the first reaction zone 336 thatdischarge effluent stream 338 is in fluid communication with one or moreinlets of the fractionating zone 310 (optionally having one or more highpressure and low pressure separation stages therebetween for recovery ofrecycle hydrogen, not shown). The fractionating zone 310 generallyincludes one or more outlets for discharging a distillate fraction 314containing cracked naphtha and cracked middle distillate/dieselproducts; and one or more outlets for discharging a bottoms fraction 316containing unconverted oil. In certain embodiments, the fractionationzone 310 includes one or more outlets for discharging gases, stream 312,typically H₂, H₂S, NH₃, and light hydrocarbons (C₁-C₄). The secondreaction zone 340 generally includes one or more inlets in fluidcommunication with one or more outlets of the coking reaction andseparation zone 320 to receive a recycle stream comprising all or aportion of a thermally cracked hydrocarbon products stream 322, shown asstream 322 a, and a source of hydrogen gas 306. The second reaction zone340 includes an effective reactor configuration with the requisitereaction vessel(s), feed heaters, heat exchangers, hot and/or coldseparators, product fractionators, strippers, and/or other units toprocess, and operates with effective catalyst(s) and under effectiveoperating conditions to carry out the desired degree of additionalconversion of the feed. One or more outlets of the second reaction zone340 that discharge effluent stream 342 are in fluid communication withone or more inlets of the fractionating zone 310 (optionally having oneor more high pressure and low pressure separation stages for recovery ofrecycle hydrogen, not shown).

The bottoms fraction 316 outlet is in fluid communication with one ormore inlets of the coking reaction and separation zone 320. In certainembodiments one or more optional additional feeds, stream 348, are influid communication with one or more inlets of the coking reaction andseparation zone 320. As shown in the integration with system 300, thecoking reaction and separation zone 320 generally includes one or moreoutlets for discharging the thermally cracked hydrocarbon productsstream 322, and a coke discharge, schematically shown as line 324,within which HPNA compounds and/or HPNA precursor compounds from thehydrocracker bottoms are contained. In certain embodiments the cokingreaction and separation zone 320 contains one or more outlets fordischarging thermally cracked distillates stream 352 (shown in dashedlines) which can include coker naphtha, coker middle distillates and/orlight coker gas oil. The outlet discharging the thermally crackedhydrocarbon products stream 322 is in fluid communication with one ormore inlets of the second reaction zone 340 for recycle of all or aportion 322 a of the recycle stream 322. In certain optionalembodiments, a portion 322 b, shown in dashed lines, is in fluidcommunication with one or more inlets of the first reaction zone 336. Incertain embodiments, a bleed stream 318 is drawn from bottoms 316upstream of the coking reaction and separation zone 320. In additionalembodiments, a bleed stream 326 is drawn from the thermally crackedhydrocarbon products stream 322 downstream of the coking reaction andseparation zone 320, in addition to or instead of bleed stream 318.Either or both of these bleed streams contain unconverted oil that ishydrogen-rich and therefore can be effectively integrated with certainfuel oil pools, or serve as feed to fluidized catalytic cracking orsteam cracking processes (not shown).

In operation of the system 300/320, a feedstock stream 302 and ahydrogen stream 304 are charged to the first reaction zone 336. Hydrogenstream 304 includes an effective quantity of hydrogen to support therequisite degree of hydrocracking, feed type, and other factors, and canbe any combination including make-up hydrogen, recycle hydrogen fromoptional gas separation subsystems (not shown) between first reactionzone 336 and fractionating zone 310, recycle hydrogen from optional gasseparation subsystems (not shown) between second reaction zone 340 andfractionating zone 310, derived from fractionator gas stream 312, and/orderived from coker gas products from coking reaction and separation zone320. The first reaction zone 336 operates under effective conditions forproduction of reaction effluent stream 338. The reaction effluent streamfurther includes HPNA compounds that were formed in the reaction zone336. One or more high pressure and low pressure separation stages can beintegrated as is known to recover recycle hydrogen between the reactionzone 336 and the fractionating zone 310. For example, effluents from thehydrocracking reaction vessel are cooled in an exchanger and sent to ahigh pressure cold or hot separator. Separator tops are cleaned in anamine unit and the resulting hydrogen rich gas stream is passed to arecycling compressor to be used as a recycle gas in the hydrocrackingreaction vessel. Separator bottoms from the high pressure separator,which are in a substantially liquid phase, are cooled and thenintroduced to a low pressure cold separator. Remaining gases includinghydrogen, H₂S, NH₃ and any light hydrocarbons, which can include C₁-C₄hydrocarbons, can be conventionally purged from the low pressure coldseparator and sent for further processing, such as flare processing orfuel gas processing. The liquid stream from the low pressure coldseparator is passed to the fractionating zone 310.

The reaction effluent stream 338 is passed to the fractionation zone310, generally to recover gas stream 312 and liquid products 314 and toseparate a bottoms fraction 316 containing HPNA compounds. Gas stream312, typically containing H₂, H₂S, NH₃, and light hydrocarbons (C₁-C₄),is discharged and recovered and can be further processed as is known inthe art, including for recovery of recycle hydrogen. In certainembodiments one or more gas streams are discharged from one or moreseparators between the reactors (not shown), or between the reactor andthe fractionator, and gas stream 312 can be optional from thefractionator. One or more cracked product streams 314 are dischargedfrom appropriate outlets of the fractionator and can be furtherprocessed and/or blended in downstream refinery operations as gasoline,kerosene and/or diesel fuel products or intermediates, and/or otherhydrocarbon mixtures that can be used to produce petrochemical products.In certain embodiments (not shown), fractionating zone 310 can operateas one or more flash vessels to separate heavy components at a suitablecut point, for example, a range corresponding to the upper temperaturerange of the desired product stream 314.

In certain embodiments, all, a major portion, a significant portion, ora substantial portion of the fractionator bottoms stream 316 containingHPNA compounds and/or HPNA precursors formed in the reaction zones ispassed to the coking reaction and separation zone 320 for treatment. Incertain embodiments a portion of the fractionator bottoms from thereaction effluent is removed as bleed stream 318. Bleed stream 318 cancontain a suitable portion (V %) of the fractionator bottoms 316, incertain embodiments about 0-10, 0-5, 0-3, 1-10, 1-5 or 1-3. HPNAcompounds and/or HPNA precursors in the hydrocracking effluentfractionator bottoms are retained in the coke phase in the cokingreaction and separation zone 320, and all or a portion of the thermallycracked hydrocarbon products stream 322 is recycled. A coke discharge324 containing HPNA compounds is removed from the system. In certainembodiments, instead of or in conjunction with bleed stream 318, aportion of the thermally cracked hydrocarbon products stream 322 isremoved from the recycle loop as bleed stream 326. Bleed stream 326 cancontain a suitable portion (V %) of the thermally cracked hydrocarbonproducts stream 322, in certain embodiments about 0-10, 0-5, 0-3, 1-10,1-5 or 1-3. In certain embodiments, all or a portion of the thermallycracked hydrocarbon products stream 322 is passed to the second reactionzone 340 as stream 322 a. In certain embodiments, all or a portion ofthe thermally cracked hydrocarbon products stream 322 is recycled to thesecond reaction zone 340 as stream 322 a, the first reaction zone 336 asstream 322 b, or both the first and second reaction zones 336 and 340.For instance, stream 322 a comprises (V %) 0-100, 0-80 or 0-50 relativeto stream 322 that is recycled to zone 340, and stream 322 b comprises0-100, 0-80 or 0-50 relative to stream 322 that is recycled to zone 336.In certain embodiments, all, a major portion, a significant portion, ora substantial portion of the thermally cracked hydrocarbon productsstream 322 is passed to the second reaction zone 340 as stream 322 a.The stream 322 is obtained from the coking reaction and separation zone320 and has a reduced concentration of HPNA compounds relative to thehydrocracker bottoms fraction. In certain embodiments, a thermallycracked distillates stream 352 (shown in dashed lines) is dischargedfrom the coking reaction and separation zone 320 which can include cokernaphtha, coker middle distillates and/or light coker gas oil. The secondreaction zone 340 operates under conditions effective for production ofthe reaction effluent stream 342, which contains converted, partiallyconverted and unconverted hydrocarbons. The second stage the reactioneffluent stream 342 is passed to the fractionating zone 310, optionallythrough one or more gas separators to recovery recycle hydrogen andremove certain light gases.

In additional embodiments, one or more optional additional feeds, stream348 can be routed to the coking reaction and separation zone 320. Incertain embodiments the only feed to the coking reaction and separationzone 320 are derived from the fractionator bottoms 316.

The first reaction zone 336 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, CSTR, or tubular reactors, inseries and/or parallel arrangement. The reactor(s) are generallyoperated under conditions effective for the desired level of treatmentand degree of conversion in the first reaction zone 336, the particulartype of reactor, the feed characteristics, and the desired productslate. For instance, these conditions can include a reaction temperature(° C.) in the range of from about 300-500, 300-475, 300-450, 330-500,330-475 or 330-450; a reaction pressure (bars) in the range of fromabout 60-300, 60-200, 60-180, 100-300, 100-200, 100-180, 130-300,130-200 or 130-180; a hydrogen feed rate (SL/L) of up to about 2500,2000 or 1500, in certain embodiments from about 800-2500, 800-2000,800-1500, 1000-2500, 1000-2000 or 1000-1500; and a feed rate liquidhourly space velocity (h⁻¹) in the range of from about 0.1-10, 0.1-5,0.1-2, 0.25-10, 0.25-5, 0.25-2, 0.5-10, 0.5-5 or 0.5-2. The catalystused in the first reaction zone 336 can comprise those havinghydrotreating functionality, and in certain embodiments those havinghydrotreating and hydrocracking functionality. In embodiments in whichcatalysts used in first reaction zone 336 possess hydrotreatingfunctionality, including hydrodesulfurization, hydrodenitrificationand/or hydrodemetallization, the focus is removal of S, N and othercontaminants, with a limited degree of conversion (for instance in therange of 10-30 V %). In embodiments in which catalysts used in firstreaction zone 336 possess hydrotreating and hydrocracking functionality,a higher degree of conversion occurs, generally above about 30 V %, forinstance in the range of about 30-60 V %.

The second reaction zone 340 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, CSTR, or tubular reactors, inseries and/or parallel arrangement. The reactor(s) are generallyoperated under conditions effective for the desired degree ofconversion, particular type of reactor, the feed characteristics, andthe desired product slate. For instance, these conditions can include areaction temperature (° C.) in the range of from about 300-500, 300-475,300-450, 330-500, 330-475 or 330-450; a reaction pressure (bars) in therange of from about 60-300, 60-200, 60-180, 100-300, 100-200, 100-180,130-300, 130-200 or 130-180; a hydrogen feed rate (SL/L) of up to about2500, 2000 or 1500, in certain embodiments from about 800-2500,800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500; and a feed rateliquid hourly space velocity (h⁻¹) in the range of from about 0.1-10,0.1-5, 0.1-2, 0.25-10, 0.25-5, 0.25-2, 0.5-10, 0.5-5 or 0.5-2. Thecatalyst used in the second reaction zone 340 can comprise those havinghydrodesulfurization, hydrodenitrification, and hydrocrackingfunctionality for further conversion of refined and partially crackedcomponents from the feedstock, and in certain embodiments those havinghydrocracking and hydrogenation functionality.

In certain embodiments, the feedstock to the reactor(s) within thehydrocracking zones (a single reactor with one bed, a single reactorwith multiple beds, or multiple reactors) is mixed with an excess ofhydrogen gas in a mixing zone. A portion of the hydrogen gas is mixedwith the feedstock to produce a hydrogen-enriched liquid hydrocarbonfeedstock. This hydrogen-enriched liquid hydrocarbon feedstock andundissolved hydrogen can be supplied to a flashing zone in which atleast a portion of undissolved hydrogen is flashed, and the hydrogen isrecovered and recycled. The hydrogen-enriched liquid hydrocarbonfeedstock from the flashing zone is supplied as a feed stream to thereactor. The liquid product stream that is recovered from the reactor isfurther processed and/or recovered as provided here.

Effective catalysts used in embodiments in which those possessinghydrotreating functionality required, for instance, in first reactionzone 228 or first reaction zone 336, are known. Such hydrotreatingcatalysts, sometimes referred to in the industry as “pretreat catalyst,”are effective for hydrotreating, and inherently a limited degree ofconversion occurs (generally below about 30 V %). The catalystsgenerally contain one or more active metal components of metals or metalcompounds (oxides or sulfides) selected from the Periodic Table of theElements IUPAC Groups 6, 7, 8, 9 and 10. One or more active metalcomponent(s) are typically deposited or otherwise incorporated on asupport, which can be amorphous and/or structured, such as alumina,silica-alumina, silica, titania, titania-silica or titania-silicates.Combinations of active metal components can be composed of differentparticles/granules containing a single active metal species, orparticles containing multiple active species. For example, effectivehydrotreating catalysts include one or more of an active metal componentselected from the group consisting of Co, Ni, W, Mo (oxides orsulfides), incorporated on an alumina support, typically with otheradditives. In certain embodiments in which an objective ishydrodenitrification and treatment of difficult feedstocks such asdemetallized oil, the supports are acidic alumina, silica alumina or acombination thereof. In embodiments in which the objective ishydrodenitrification with increased hydrocarbon conversion, the supportsare silica alumina, or a combination thereof. Silica alumina is usefulfor difficult feedstocks for stability and enhanced cracking. Thecatalyst particles are provided in particulate form of suitabledimension, such as granules, extrudates, tablets, or pellets, and may beformed into various shapes such as spheres, cylinders, trilobes,quadrilobes or natural shapes. In certain embodiments, the catalystparticles have a pore volume in the range of about (cc/gm) 0.15-1.70,0.15-1.50, 0.30-1.50 or 0.30-1.70; a specific surface area in the rangeof about (m²/g) 100-400, 100-350, 100-300, 150-400, 150-350, 150-300,200-400, 200-350 or 200-300; and an average pore diameter of at leastabout 10, 50, 100, 200, 500 or 1000 angstrom units. The active metalcomponent(s) are incorporated in an effective concentration, forinstance, in the range of (wt % based on the mass of the oxides,sulfides or metals relative to the total mass of the catalysts) 1-40,1-30, 1-10, 1-5, 2-40, 2-30, 2-10, 3-40, 3-30 or 3-10. In certainembodiments, the active metal component(s) include one or more of Co,Ni, W and Mo, and effective concentrations are based on all the mass ofactive metal components on an oxide basis. In certain embodiments,hydrotreating catalysts are configured in one or more beds selected fromNi/W/Mo, Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo. Combinations of one or morebeds of Ni/W/Mo, Co/Mo, Ni/Mo, Ni/W and Co/Ni/Mo, are useful fordifficult feedstocks such as demetallized oil, and to increasehydrocracking functionality. In additional embodiments, the catalystincludes a bed of Co/Mo catalysts and a bed of Ni/Mo catalysts.

Effective catalysts used in embodiments where those possessinghydrotreating and hydrocracking functionality are required, forinstance, reaction zone 106, first reaction zone 228 or first reactionzone 336, are known. These catalysts, effective for hydrotreating and adegree of conversion generally in the range of about 30-60 V % containone or more active metal components of metals or metal compounds (oxidesor sulfides) selected from the Periodic Table of the Elements IUPACGroups 6, 7, 8, 9 and 10. One or more active metal component(s) aretypically deposited or otherwise incorporated on a support, which can beamorphous and/or structured, such as alumina, silica-alumina, silica,titania, titania-silica, titania-silicates, or zeolites. Combinations ofactive metal components can be composed of different particles/granulescontaining a single active metal species, or particles containingmultiple active species. For example, effectivehydrotreating/hydrocracking catalysts include one or more of an activemetal component selected from the group consisting of Co, Ni, W, Mo(oxides or sulfides), incorporated on acidic alumina, silica alumina,zeolite or a combination thereof. In embodiments in which zeolites areused, they are conventionally formed with one or more binder componentssuch as alumina, silica, silica-alumina and mixtures thereof. In certainembodiments in which an objective is hydrodenitrification and treatmentof difficult feedstocks such as demetallized oil, the supports areacidic alumina, silica alumina or a combination thereof. In embodimentsin which the objective is hydrodenitrification with increasedhydrocarbon conversion, the supports are silica alumina, or acombination thereof. Silica alumina is useful for difficult feedstocksfor stability and enhanced cracking. The catalyst particles are providedin particulate form of suitable dimension, such as granules, extrudates,tablets, or pellets, and may be formed into various shapes such asspheres, cylinders, trilobes, quadrilobes or natural shapes. In certainembodiments, the catalyst particles have a pore volume in the range ofabout (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or 0.30-1.70; a specificsurface area in the range of about (m²/g) 100-900, 100-500, 100-450,180-900, 180-500, 180-450, 200-900, 200-500 or 200-450; and an averagepore diameter of at least about 45, 50, 100, 200, 500 or 1000 angstromunits. The active metal component(s) are incorporated in an effectiveconcentration, for instance, in the range of (wt % based on the mass ofthe oxides, sulfides or metals relative to the total mass of thecatalysts) 1-40, 1-30, 1-10, 1-5, 2-40, 2-30, 2-10, 3-40, 3-30 or 3-10.In certain embodiments, the active metal component(s) include one ormore of Co, Ni, W and Mo, and effective concentrations are based on allthe mass of active metal components on an oxide basis. In certainembodiments, one or more beds are provided in series in a single reactoror in a series of reactors. For instance, a first catalyst bedcontaining active metals on silica alumina support is provided forhydrodenitrogenation, hydrodesulfurization and hydrocrackingfunctionalities, followed by a catalyst bed containing active metals onzeolite support for hydrocracking functionality.

Effective catalysts used in embodiments where those possessinghydrocracking functionality, for instance, second reaction zone 232 orsecond reaction zone 340, are known. These catalysts, effective forfurther conversion of refined and partially cracked components from thefeedstock, contain one or more active metal components of metals ormetal compounds (oxides or sulfides) selected from the Periodic Table ofthe Elements IUPAC Groups 6, 7, 8, 9 and 10. One or more active metalcomponent(s) are typically deposited or otherwise incorporated on asupport, which can be amorphous and/or structured, such assilica-alumina, silica, titania, titania-silica, titania-silicates, orzeolites. Combinations of active metal components can be composed ofdifferent particles/granules containing a single active metal species,or particles containing multiple active species. In embodiments in whichzeolites are used, they are conventionally formed with one or morebinder components such as alumina, silica, silica-alumina and mixturesthereof. For example, effective hydrocracking catalysts include one ormore of an active metal component selected from the group consisting ofNi, W, Mo (oxides or sulfides), incorporated on acidic alumina, silicaalumina, zeolite or a combination thereof. The catalyst particles areprovided in particulate form of suitable dimension, such as granules,extrudates, tablets, or pellets, and may be formed into various shapessuch as spheres, cylinders, trilobes, quadrilobes or natural shapes. Incertain embodiments, the catalyst particles have a pore volume in therange of about (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or 0.30-1.70; aspecific surface area in the range of about (m²/g) 100-900, 100-500,100-450, 180-900, 180-500, 180-450, 200-900, 200-500 or 200-450; and anaverage pore diameter of at least about 45, 50, 100, 200, 500 or 1000angstrom units. The active metal component(s) are incorporated in aneffective concentration, for instance, in the range of (wt % based onthe mass of the oxides, sulfides or metals relative to the total mass ofthe catalysts) 1-40, 1-30, 1-10, 1-5, 2-40, 2-30, 2-10, 3-40, 3-30 or3-10. In certain embodiments, the active metal component(s) include oneor more of Co, Ni, W and Mo, and effective concentrations are based onall the mass of active metal components on an oxide basis. In a typicalhydrocracking reaction scheme, the main cracking catalyst bed or bedsare followed by post treat catalyst to remove mercaptans formed duringhydrocracking. Typical supports for post treat catalyst aresilica-alumina, zeolites of combination thereof.

Effective catalysts used in embodiments where those possessinghydrocracking and hydrogenation functionality, for instance, secondreaction zone 232 or second reaction zone 340, are known. Thesecatalysts, effective for further conversion and also for hydrogenationof refined and partially cracked components from the feedstock, containone or more active metal components of metals or metal compounds (oxidesor sulfides) selected from the Periodic Table of the Elements IUPACGroups 6, 7, 8, 9 and 10. One or more active metal component(s) aretypically deposited or otherwise incorporated on a support, which can beamorphous and/or structured, such as alumina, silica-alumina, silica,titania, titania-silica, titania-silicates, or zeolites. Combinations ofactive metal components can be composed of different particles/granulescontaining a single active metal species, or particles containingmultiple active species. For example, effective hydrocracking catalystsinclude one or more of an active metal component selected from the groupconsisting of Co, Ni, W, Mo (oxides), incorporated on acidic alumina,silica alumina, zeolite or a combination thereof. The catalyst particlesare provided in particulate form of suitable dimension, such asgranules, extrudates, tablets, or pellets, and may be formed intovarious shapes such as spheres, cylinders, trilobes, quadrilobes ornatural shapes. In certain embodiments, the catalyst particles have apore volume in the range of about (cc/gm) 0.15-1.70, 0.15-1.50,0.30-1.50 or 0.30-1.70; a specific surface area in the range of about(m²/g) 100-900, 100-800, 100-500, 100-450, 180-900, 180-800, 180-500,180-450, 200-900, 200-800, 200-500 or 200-450; and an average porediameter of at least about 45, 50, 100, 200, 500 or 1000 angstrom units.The active metal component(s) are incorporated in an effectiveconcentration, for instance, in the range of (wt % based on the mass ofthe oxides, sulfides or metals relative to the total mass of thecatalyst) 0.01-40, 0.01-30, 0.01-10, 0.01-5, 1-40, 1-30, 1-10, 1-5,2-40, 2-30, 2-10, 3-40, 3-30 or 3-10. In certain embodiments, the activemetal component(s) include one or more of Co, Ni, W and Mo, andeffective concentrations are based on all the mass of active metalcomponents on an oxide basis. In embodiments in which one or moreupstream reaction zone(s) reduces contaminants such as S and N, so thathydrogen sulfide and ammonia are minimized in the reaction zone, activemetal components effective as hydrogenation catalysts can include one ormore noble metals such as platinum, palladium or rhodium, alone or incombination with other active metals such as Ni. Such noble metals canbe provided in the range of (wt % based on the mass of the metalrelative to the total mass of the catalyst) 0.01-5, 0.01-2, 0.05-5,0.05-2, 0.1-5, 0.1-2, 0.5-5, or 0.5-2.

In certain embodiments, the catalyst and/or the catalyst support isprepared in accordance with U.S. Pat. No. 9,221,036 and related U.S.Pat. No. 10,081,009 (jointly owned by the owner of the presentapplication), which are incorporated herein by reference in theirentireties, includes a modified USY zeolite support having one or moreof Ti, Zr and/or Hf substituting the aluminum atoms constituting thezeolite framework thereof.

In embodiments described herein using zeolite-based hydrocrackingcatalysts, HPNA compounds have relatively greater tendency to accumulatein the recycle stream due to the inability for these larger molecules todiffuse into the catalyst pore structure, particularly at relativelylower hydrogen partial pressure levels in the reactor. For instance, athydrogen partial pressures less than about 100 bars, HPNA formation isknown to reduce catalyst lifecycle to by 30-70% depending upon thefeedstock processed and targeted conversion rate. However, according tothe process herein, by removing HPNA compounds from the recycle stream,the lifecycle of such zeolite catalyst is increased.

The coking reaction and separation zones 120, 220 and 320 integrated inhydrocracking operations 100, 200 and 300 described herein, andvariations thereto apparent to a person having ordinary skill in theart, are effective for thermal cracking of a hydrocracker bottomsfraction of unconverted oil, and recycling all or a portion of thermallycracked hydrocarbon products within the hydrocracking operation. In thismanner, HPNA compounds and/or HPNA precursor compounds that were formedin the hydrocracking reaction zone(s) (and are in the unconverted oil)are removed from circulation by remaining with the coke phase, and incertain embodiments by thermal cracking to form lighter hydrocarbons.Thermal treatment in the coking zone can dealkylate alkyl groups thatare attached to the HPNA compounds or can crack any paraffinic ornaphthenic bonds present in the HPNA compounds. HPNA compounds and HPNAprecursor compounds that are not cracked remain in the coke phase orthey tend to polymerize to form heavier HPNA compounds or coke and willnot be recycled, thereby minimizing fouling or other detriments to thecatalysts in the reaction zones. The hydrocracker bottom stream, whichis rich in hydrogen due to its highly paraffinic nature, serves as ahydrogen donor and advantageously stabilizes radicals during thermalcracking and as a result minimizes coke formation.

In addition, the hydrocracker bottoms fraction is low in S and N, and isfree of metals or substantially free of metals. Accordingly, this streamserves to dilute other S rich coking feedstreams when used incombination and as a result, higher grade coke production from thedelayed coking is facilitated as compared to coking operations withoutuse of the hydrocracker bottoms fraction.

The coking zone can operate in accordance with known cokers used in oilrefineries, including more commonly known delayed coker units, and incertain arrangements a fluid coking process. In general, cokingoperations are carbon rejection processes that are used to convert lowervalue atmospheric or vacuum distillation residue streams to lighterproducts, thermally cracked hydrocarbon products. Typically thesethermally cracked hydrocarbon products can be hydrotreated and/orsubjected to other known treatment processes to produce transportationfuels such as gasoline and diesel, and increments of light productswhich can be further desulfurized, treated, and/or concentrated toproduce petrochemicals. In the integrated processes and systems herein,all or a portion of the thermally cracked hydrocarbon products arerecycled to the hydrocracking operation as stream 122, 222 or 322.

The thermally cracked hydrocarbon products that are recycled to thehydrocracking operation, shown as streams 122, 222 and 322 above andstreams 422, 522 and 622 below, can include coker gas oil, coker middledistillates and coker naphtha; coker gas oil, coker middle distillatesand coker heavy naphtha; coker gas oil and coker middle distillates;coker gas oil and heavy coker middle distillates; coker gas oil; orheavy coker gas oil. In certain embodiments, one or more cokerdistillate streams are also provided, shown as shown as streams 152, 252and 352 above and streams 452, 552 and 652 below, which can containdistillate products from the fractionating zone that are not passed withthermally cracked hydrocarbon products that are recycled to thehydrocracking operation. In certain embodiments, depending on the S andN content of the coker distillate stream 152, 252, 352 452, 552 or 652,all or a portion can be combined with a hydrocracker distillate stream.

Coking of residuum from heavy high sulfur, or sour, crude oils istypically carried out to convert part of the material to more valuableliquid and gas products. Typical coking processes include delayed cokingand fluid coking. The treatment of coke varies depending on the type ofcoking process and the quality of the coke. In certain embodiments, forinstance with delayed coking units, resulting coke is removed fromdrums, and is generally treated as a low value by-product or recoveredfor various uses depending upon its quality. In a fluid coking unit,coke is removed as particles and a portion is recycled to provide hotsurfaces for thermal cracking.

A delayed coking unit and its general process description is shown andschematically illustrated below. The coker feedstream is mixed withsteam and the mixture rapidly heated in a coking furnace to a cokingtemperature, and then fed to a coking drum. The hot mixed cokerfeedstream is maintained in the coke drum at coking conditions oftemperature and pressure where the feed decomposes or cracks to formcoke and volatile components. The volatile components are recovered asvapor and transferred to a coking product fractionator. One or moreheavy fractions of the coke drum vapors can be condensed, for example byquenching or heat exchange. In certain embodiments the coke drum vaporsare contacted with heavy gas oil in the coking unit productfractionator, and heavy fractions form all or part of a recycle oilstream having condensed coking unit product vapors and heavy gas oil. Incertain embodiments, heavy gas oil from the coking feed fractionator isadded to a flash zone of the fractionator to condense the heaviestcomponents from the coking unit product vapors. Delayed coking units aretypically configured with two or more parallel drums and operated in analternating swing mode if there are two drums, or in a sequentiallycyclic operating mode if there are three or more drums. Parallel cokingdrum trains, with two or more drums per train, are also possible. Whenthe coke drum is full of coke, the feed is switched to another drum, andthe full drum is cooled. Liquid and gas streams from the coke drum arepassed to a coking product fractionator for recovery. Any hydrocarbonvapors remaining in the coke drum are removed, for instance by steaminjection. The coke remaining in the drum is typically cooled with waterand then removed from the coke drum by conventional methods, such as byhydraulic and/or mechanical techniques to remove green coke from thedrum walls for recovery.

Referring to FIG. 4, an embodiment of a coking reaction and separationzone 420, including a coking zone operating as a delayed coker and anassociated fractioning zone, is shown integrated with a hydrocrackingsystem 400, which can be any suitable hydrocracking unit, for instancesimilar to any of the systems 100, 200 or 300 described herein, and thatgenerally produces a hydrocracked bottoms fraction 416 and a distillatefraction 414. In certain embodiments, the products are the thermallycracked hydrocarbon products stream 422 (all or a portion of which is influid communication with the hydrocracking system 400 as a recyclestream) and petroleum coke 424. In additional embodiments, the cokingreaction and separation zone 420 produces a first thermally crackedhydrocarbon products stream 452, a second thermally cracked hydrocarbonproducts stream 422 (all or a portion of which is in fluid communicationwith the hydrocracking system 400 as a recycle stream) and petroleumcoke 424.

The coking reaction and separation zone 420 includes a coking furnace454, a coking reaction zone 450 (shown as parallel coking drum 450 a and450 b) and a coking product fractionator 460. A coker furnace feed 480is in fluid communication with an inlet of the coking furnace 454. Thecoker furnace feed 480 include one or more of a hydrocracker bottomsfraction 416 (corresponding to streams 116, 216, 316), an additionalfeedstock 448 (corresponding to streams 148, 248, 348), and/or a bottomsstream 446 from the coking product fractionator 460. A heated feedstreamfrom an outlet of the coking furnace 454 is in fluid communication withan inlet of the coking reaction zone 450, and a coker liquid and gasstream 456 is discharged from an outlet of the coking reaction zone 450.The outlet discharging the coker liquid and gas stream 456 is in fluidcommunication with an inlet of the coking product fractionator 460. Thecoking zone 420 also includes associated apparatus or sub-systems forrecovery and handling of coke 424, for instance, hydraulic and/ormechanical cutters.

The coker fractionating zone 460 includes one or more inlets in fluidcommunication with the coker liquid and gas stream 456, and in certainembodiments also in fluid communication with the hydrocracker bottomsfraction 416 and/or the additional feedstock 448. The cokerfractionating zone 460 also includes one or more outlets dischargingnaphtha, middle distillate and gas oil range coker products. A thermallycracked hydrocarbon products stream 422, or a first thermally crackedhydrocarbon products stream 452 and a second thermally crackedhydrocarbon products stream 422, are discharged from outlets of thecoking product fractionator 460. One or more light outlets can also beprovided (not shown), for instance, discharging gases H₂, H₂S, NH₃, andC₁-C₄ hydrocarbons. One or more bottoms outlets 446 are provided, forinstance, including hydrocarbon components having an initial boilingpoint corresponding to that of vacuum residue. This stream can berecycled to the furnace as all or a portion of stream 480.

In certain embodiments the fractionating zone 460 includes as outlets afirst thermally cracked hydrocarbon products stream 452 and a secondthermally cracked hydrocarbon products stream 422. One or more lightoutlets can also be provided (not shown), for instance, discharginggases H₂, H₂S, NH₃, and C₁-C₄ hydrocarbons. In certain embodiments theselight products can be included with a first thermally crackedhydrocarbon products stream 452 containing unstabilized naphtha (full orpartial range naphtha, or light naphtha).

The coker furnace feed 480 is charged to the coking furnace 454 wherethe contents are rapidly heated to a coking temperature and then fed tothe coking drum 450 a or 450 b. The coking unit 420 can be configuredwith two or more parallel drums 450 a and 450 b and can be operated in aswing mode, such that when one of the drums is filled with coke, thefeed is transferred to the empty parallel drum so that accumulated coke424 can be recovered from the filled drum.

The coker liquid and gas products are recovered as a the coker liquidand gas stream 456 from one or more outlets of the coker drum 450 a or450 b. The coker liquid and gas stream 456 is passed to the cokingproduct fractionator 460, which produces the thermally crackedhydrocarbon products stream 422. In certain embodiments the hydrocrackerbottoms fraction 416 and/or an additional feed 448 is also charged tothe coking product fractionator 460. In certain embodiments, the cokerliquid and gas stream 456 is fractionated to yield separate productstreams that can include the first thermally cracked hydrocarbonproducts stream 452, and the second thermally cracked hydrocarbonproducts stream 422. In certain embodiments, all, a major portion, asignificant portion, or a substantial portion of the thermally crackedhydrocarbon products stream 422 is used as a recycle stream within thehydrocracking system 400. The coker fractionator bottoms stream 446 canbe recycled as all or a portion of the coker furnace stream 480. Anyhydrocarbon vapors remaining in the coke drum are removed by steaminjection. The coke is cooled with water and then removed from the cokedrum using hydraulic and/or mechanical means.

In operation of the delayed coker, the coker feed 480 and steam areintroduced into the coking furnace 454 for heating to a predeterminedtemperature or temperature range that is similar to the cokingtemperature. In typical operations the temperature of the heated cokerfeedstream is closely monitored and controlled in the furnace utilizingappropriately positioned thermocouples, or other suitabletemperature-indicating sensors to avoid or minimize the undesirableformation of coke in the tubes of the furnace. The sensors and controlof the heat source, such as open flame heaters, can be automated as isknown to those of skill of the art. For example, in known delayedcokers, a fired furnace or heater with horizontal tubes is used to reachthermal cracking temperatures, for instance, in the range of about425-650, 425-530, 425-510, 425-505, 425-500, 450-650, 450-530, 450-510,450-505, 450-500, 480-650, 480-530, 480-510, 480-505 or 480-500° C. Witha short residence time in the furnace tubes of the coking furnace 454,and with addition of steam, coking of the feed material on the furnacetubes is minimized or obviated, and coking is thereby “delayed” until itis discharged into relatively larger coking drums in the coking reactionzone 450 downstream of the heater. In addition, the necessary heat forcoking is provided in the coking furnace 454.

The flow of the heated coker feedstream from the coking furnace 454 isdirected into one of the coking drums 450 a or 450 b via a feed line byadjustment of an inlet control valve, for instance, a three-way valve.The coking unit process can be conducted as a semi-continuous process byproviding at least two vertical coking drums that are operated in swingmode. This allows the flow through the tube furnace to be continuous.The feedstream is switched from one to another of the at least twodrums. In a coking unit with two drums, one drum is on-line filling withcoke while the other drum is being steam-stripped, cooled, decoked,pressure checked and warmed up. The overhead vapors from the coke drumsflow from the drum used for thermal cracking to the fractionating zonein a continuous manner.

The coke drum is maintained at coking conditions of temperature andpressure where the feed decomposes or cracks to form coke and volatilecomponents. The hydrocracker bottom stream, which is rich in hydrogendue to its highly paraffinic and naphthenic nature, serves as a hydrogendonor during these cracking reactions, and advantageously stabilizesradicals during thermal cracking and as a result minimizes cokeformation. The volatile components are recovered as vapor andtransferred to the coking unit product fractionator. In certainembodiments, heavy gas oil from the fractionator is added to the flashzone of the fractionator to condense the heaviest components from thecoking unit product vapors. The heaviest fraction of the coke drumvapors can be condensed by other techniques, such as heat exchange. Incertain embodiments, as in commercial operations, incoming vapors can becontacted with heavy gas oil in the coking unit product fractionator.Conventional heavy recycle oil includes condensed coking unit productvapors and unflashed heavy gas oil.

When a drum 450 a or 450 b contains the predetermined maximum amount ofcoke, the inlet control valve is adjusted to direct the heated cokerfeedstream into the other drum 450 b or 450 a. Substantially at the sametime, a coking drum outlet valve is adjusted so that the liquid and gasproducts are discharged through the appropriate line as the coker liquidand gas stream 456 that is passed to the fractionating zone 460. Anyhydrocarbon vapors remaining in the coke drum are typically removed bysteam injection. Typically, the coking zone 420 includes associatedapparatus, for instance, hydraulic and/or mechanical cutters, wherebycoke is cooled with water and then removed from the coke drum usinghydraulic and/or mechanical cutters while that coking drum istemporarily decommissioned. Coke that is subsequently removed from adrum when it is out of service is schematically represented as lines424.

The operating temperature (° C.) in the coking drums 450 can range fromabout 425-650, 425-510, 425-505, 425-500, 450-650, 450-510, 450-505,450-500, 485-650, 485-510, 485-505, 485-500, 470-650, 470-510, 470-505or 470-500. The operating pressure (bars) in the coking drum can be inthe range of about 1-20, 1-10 or 1-3, and in certain embodiments ismildly super-atmospheric. In certain embodiments of the process, steamis introduced or injected with the heated residue into the cokingfurnace, for instance with a steam introduction rate of about 0.1-3,0.5-3 or 1-3 wt % relative to the heated residue, to increase thevelocity in the tube furnace, and to reduce the partial pressure of thefeedstock oil in the drum. The steam also serves to increase the amountof gas oil removed from the coke drums. Steam also assists in decokingof the tubes in the event of a brief interruption of the feed flow. Thecoking in each drum can occur in cycles, for instance, in the range ofabout 10-30, 10-24, 10-18, 12-30, 12-24, 12-18, 16-30, 16-24 or 16-18hours.

In certain embodiments, a fluid coking process is used, whereincirculated coke particles contact the feed and in which coking occurs onthe surface of the coke particles, for instance similar to aFlexicoking™ process commercially available from ExxonMobil. Referringto FIG. 5, an embodiment of a coking reaction and separation zone 520,including a coking zone operating as a fluid coker and an associatedfractioning zone, is shown integrated with a hydrocracking system 500,which can be any suitable hydrocracking unit, for instance similar toany of the systems 100, 200 or 300 described herein, and that generallyproduces a hydrocracked bottoms fraction 516 and a distillate fraction514. In certain embodiments, the products are the thermally crackedhydrocarbon products stream 522 (all or a portion of which is in fluidcommunication with the hydrocracking system 500 as a recycle stream) andcoke 568. In additional embodiments, the coking reaction and separationzone 520 produces a first thermally cracked hydrocarbon products stream552, a second thermally cracked hydrocarbon products stream 522 (all ora portion of which is in fluid communication with the hydrocrackingsystem 500 as a recycle stream) and coke 568.

The coking reaction and separation zone 520 includes a coking furnace554, a coking reaction zone 550 and a coking product fractionator 560.In addition, suitable systems are provided to facilitate circulation ofcoke particles including a coke combusting zone 562 and a finesseparation zone 566. A coker furnace feed 580 is in fluid communicationwith an inlet of the coking furnace 554. The coker furnace feed 580include one or more of a hydrocracker bottoms fraction 516(corresponding to streams 116, 216, 316), an additional feedstock 548(corresponding to streams 148, 248, 348), and/or a bottoms stream 546from the coking product fractionator 560. A heated feedstream from anoutlet of the coking furnace 554 is in fluid communication with an inletof the coking reaction zone 550, and a coker liquid and gas stream 556is discharged from an outlet of the coking reaction zone 550. The outletdischarging the coker liquid and gas stream 556 is in fluidcommunication with an inlet of the coking product fractionator 560.

The coker fractionating zone 560 includes one or more inlets in fluidcommunication with the coker liquid and gas stream 556, and in certainembodiments also in fluid communication with the hydrocracker bottomsfraction 516 and/or the additional feedstock 548. The cokerfractionating zone 560 also includes one or more outlets dischargingnaphtha, middle distillate and gas oil range coker products. A thermallycracked hydrocarbon products stream 522, or a first thermally crackedhydrocarbon products stream 552 and a second thermally crackedhydrocarbon products stream 522, are discharged from outlets of thecoking product fractionator 560. One or more light outlets can also beprovided (not shown), for instance, discharging gases H₂, H₂S, NH₃, andC₁-C₄ hydrocarbons. One or more bottoms outlets 546 are provided, forinstance, including hydrocarbon components having an initial boilingpoint corresponding to that of vacuum residue. This stream can berecycled to before the furnace as all or a portion of stream 580.

In certain embodiments the fractionating zone 560 includes as outlets afirst thermally cracked hydrocarbon products stream 552 and a secondthermally cracked hydrocarbon products stream 522. One or more lightoutlets can also be provided (not shown), for instance, discharginggases H₂, H₂S, NH₃, and C₁-C₄ hydrocarbons. In certain embodiments theselight products can be included with a first thermally crackedhydrocarbon products stream 552 containing unstabilized naphtha (full orpartial range naphtha, or light naphtha).

The coker furnace feed 580 is charged to a coking furnace 554 where thecontents are rapidly heated to a coking temperature and then fed to acoking drum 550. The coking reaction zone 550 includes a reactor havingone or more inlets that receive a heated feedstream by spraying or othersuitable means of injection. A portion of the coke effluent 524, inparticle form, is discharged via one or more outlets, and is in fluid orparticulate communication with the coke combusting zone 562. Heated coke564 is discharged from one or more outlets of the coke combusting zone562 and is in fluid or particulate communication with one or more inletsof the coking drum 550.

The coker liquid and gas products are recovered as the coker liquid andgas stream 556 from one or more outlets of the coking drum 550,generally through a fines separation zone 566 for recovery of fine cokeparticles. The coker liquid and gas stream 556 is passed to the cokingproduct fractionator 560, which produces the thermally crackedhydrocarbon products stream 522. In certain embodiments the hydrocrackerbottoms fraction 516 and/or an additional feed 548 is also charged tothe coking product fractionator 560. In certain embodiments, the cokerliquid and gas stream 556 is fractionated to yield separate productstreams that can include the first thermally cracked hydrocarbonproducts stream 552, and the second thermally cracked hydrocarbonproducts stream 522. In certain embodiments, all, a major portion, asignificant portion, or a substantial portion of the thermally crackedhydrocarbon products stream 522 is used as a recycle stream within thehydrocracking system 500. The coker fractionator bottoms stream 546 canbe recycled as all or a portion of the coker furnace stream 580.

In operation of the fluid coking unit, the coker feed 580 and steam areintroduced into the coking furnace 554 for heating to a predeterminedtemperature or temperature range, for instance, typically at about thecoking temperature. For example, a fired furnace or heater withhorizontal tubes is used to reach temperature levels that are at orbelow thermal cracking temperatures, for instance, in the range (° C.)of about 425-650, 425-570, 425-525, 450-650, 450-570, 450-525, 485-650,485-570 or 485-525. With a short residence time in the furnace tubes ofthe coking furnace 554, and with addition of steam, coking of the feedmaterial on the furnace tubes is minimized or obviated. In the fluidcoking unit, coking occurs on coke particles in the coker reactor 550.Further, additional heat for coking is provided by recirculatingcombusted heated coke particles 564 in the coking drum 550.

All or a portion of the coke product 524 is burned to provide additionalheat for coking reactions to the feed into gases, distillate liquids,and coke. Coking occurs on the surface of circulating coke particles ofcoke. Coke is heated by burning the surface layers of accumulated cokein the coke combustion zone 562, by partial combustion of coke produced.The products of coking are sent to the fractionating zone after recoveryof fine coke particles in the separation zone 566. Steam can also beadded at the bottom of the reactor (not shown), for instance, in ascrubber to add fluidization and to strip heavy liquids sticking to thesurface of coke particles before they are sent to the burner. Coke isdeposited in layers on the fluidized coke particles in the reactor. Airis injected into the burner for combustion to burn a portion of the cokeproduced in the reactor. A portion of the combusted particles arereturned to the reactor, heated coke 564, and the remainder is drawn outas coke 568.

The operating temperature (° C.) in the coking drum 550 can range fromabout 450-760, 450-650, 450-570, 470-760, 470-650, 470-570, 510-760,510-650 or 510-570. The operating pressure (bars) can be in the range ofabout 1-20, 1-10 or 1-3, and in certain embodiments is mildlysuper-atmospheric. In certain embodiments of the process, steam isintroduced or injected with the heated residue into the coking furnace,for instance in an amount of about 0.1-3, 0.5-3 or 1-3 wt %.

In certain embodiments, a coking and separation zone is provided withunits similar to those shown in FIG. 4 or 5, with an additional materialto enhance removal of HPNA and/or HPNA precursor compounds. Referring toFIG. 6, a coking and separation zone 620 is shown operating as a fluidcoker integrated with a hydrocracking system 600, which can be anysuitable hydrocracking unit, for instance similar to any of the systems100, 200 or 300 described herein, and that generally produces ahydrocracked bottoms fraction 616 and a distillate fraction 614. Thecoking and separation zone 620 generally includes a coking drum orvessel 650 that discharges a coker liquid and gas stream 656; a cokingfractionator 660 that discharges a thermally cracked hydrocarbonproducts stream 622, or a first thermally cracked hydrocarbon productsstream 652 and a second thermally cracked hydrocarbon products stream622, and a bottoms stream 646; and a coking furnace 654 that receives acoker furnace feed 680. The coker furnace feed 680 include one or moreof a hydrocracker bottoms fraction 616 (corresponding to streams 116,216, 316), an additional feedstock 648 (corresponding to streams 148,248, 348), and/or the bottoms stream 646 from the coking productfractionator 660. A source of additional material 672 is provided influid or particulate communication with the coking drum 650 inlet, forinstance, via the initial feedstream. While schematically shown upstreamof the coking furnace 654, the additional material 672 can be addeddownstream of the coking furnace. In embodiments in which there is acoker recycle stream from the coking fractionator 660 to the coking drumor vessel 650, the source of additional material can be integrated inthe fractionator so that the coker recycle stream contains catalystmaterial. The additional material 672 can be added to the coker feed, oradmixed with use of a separate mixing zone, such as an in-line mixingapparatus or a separate mixing apparatus (not shown). In certainembodiments (not shown), additional material 672 can be metered orotherwise charged directly to the coking drum or vessel 650.

In embodiments in which additional material is catalyst material,suitable catalysts include those having functionality to stabilize thefree radicals formed by the thermal cracking and to thereby enhance thethermal cracking reactions. The catalyst material can be in homogeneousoil-soluble form, heterogeneous supported catalysts, or a combinationthereof.

In certain embodiments, the additional material 672 is a heterogeneouscatalyst material that can be added to the fractionator bottoms priorcoking. Suitable heterogeneous catalyst materials include active metalsdeposited or otherwise incorporated on a support material. Theheterogeneous catalyst materials used in embodiments herein aregenerally granular in nature, and the support material can be selectedfrom the group consisting of silica, alumina, silica-alumina,titania-silica, molecular sieves, silica gel, activated carbon,activated alumina, silica-alumina gel, zinc oxide, clays (for instance,attapulgus clay), fresh catalyst materials (including zeolitic catalyticmaterials), used catalyst materials (including zeolitic catalyticmaterials), regenerated catalyst materials (including zeolitic catalyticmaterials) and combinations thereof. The active metals of theheterogeneous catalyst material include one or more active metalcomponents of metals or metal compounds (oxides or sulfides) selectedfrom the Periodic Table of the Elements IUPAC Groups 4, 5, 6, 7, 8, 9and 10. In certain embodiments, the active metal component can be one ormore metals or metal compounds (oxides or sulfides) including Mo, V, W,Cr or Fe. In certain embodiments the active metal component can beselected from the group consisting of vanadium pentoxide, molybdenumalicyclic and aliphatic carboxylic acids, molybdenum naphthenate, nickel2-ethylhexanoate, iron pentacarbonyl, molybdenum 2-ethyl hexanoate,molybdenum di-thiocarboxylate, nickel naphthenate and iron naphthenate.In certain embodiments, Mo and Mo compounds are used as the active metalcomponent of a heterogeneous catalyst material. The heterogeneouscatalyst material is provided in particulate form of suitable dimension,such as granules, extrudates, tablets, or pellets, may be formed intovarious shapes such as spheres, cylinders, trilobes, quadrilobes ornatural shapes, possess average particle diameters (mm) of about0.01-4.0, 0.1-4.0, or 0.2-4.0, pore sizes (nm) of about 1-5,000 or5-5,000, possess pore volumes (cc/g) of about 0.08-1.2, 0.3-1.2 or0.5-1.2, in certain embodiments at least 1.0, and possess a surface areaof at least about 100 m²/g.

In embodiments in which additional material 672 is heterogeneouscatalyst material, it can be added upstream of the coking furnace, or inan optional embodiment, downstream of the furnace. A mixing zone can beused to mix the catalyst and coker feed. In addition, as catalystmaterial can be metered or otherwise charged directly to the coking drumor vessel 650, or metered or otherwise charged directly to thefractionating zone 660, as noted herein. In embodiments in whichheterogeneous catalyst is used, the amount (ppmw) can be about 1-20,000,10-20,000, 100-20,000, 1-10,000, 10-10,000, 100-10,000, 1-5,000,10-5,000, 100-5,000, 1-1,000, 10-1,000 or 100-1,000 relative to theweight of the total coker feedstream (stream 616 and in certainembodiments also stream 648), and can be determined as is known in theart, for instance based upon factors including the characteristics ofthe crude oil and its residue, the type of catalyst used and the cokingunit operating conditions.

In certain embodiments, a homogenous catalyst is used. For instance,effective homogeneous catalysts include those that are oil-soluble andcontain one or more active metal components of metals or metal compounds(oxides, sulfides, or salts of organo-metal complexes) selected from thePeriodic Table of the Elements IUPAC Groups 4, 5, 6, 7, 8, 9 and 10. Incertain embodiments, homogeneous catalysts are or contain as an activemetal component a transition metal-based compound derived from anorganic acid salt or an organo-metal compound containing Mo, V, W, Cr orFe. In certain embodiments homogeneous catalysts can be, or contain anactive metal compound, that is selected from the group consisting ofvanadium pentoxide, molybdenum alicyclic and aliphatic carboxylic acids,molybdenum naphthenate, nickel 2-ethylhexanoate, iron pentacarbonyl,molybdenum 2-ethyl hexanoate, molybdenum di-thiocarboxylate, nickelnaphthenate and iron naphthenate. In certain embodiments, Mo and Mocompounds are used as homogeneous catalyst material. The totalconcentration (ppmw, based on the total feedstock weight) of thecatalyst material can be in the range of 100-20,000, 300-20,000,500-20,000, 1,000-20,000, 100-5,000, 300-5,000, 500-5,000, 1,000-5,000,100-1,500, 300-1,500, 500-1,500, 1,000-1,500, 100-1,200, 300-1,200 or500-1,200.

The homogeneous catalyst can be added upstream of the coking furnace, orin an optional embodiment, downstream of the furnace. Since the catalystis homogeneous and oil-soluble, it can be added directly to the cokingzone or in certain embodiments to the fractionator. If the homogeneouscatalyst is prepared from metal oxides or conditioned before use, aseparate step is carried for catalyst preparation as is known in theart. The amount of catalyst material (ppmw) can range from 1-10,000,10-10,000, 100-10,000, 1-5,000, 10-5,000, 100-5,000, 1-1,000, 10-1,000,100-1,000, 1-100 or 10-100 relative to the weight of the total cokerfeedstream (stream 616 and in certain embodiments also stream 648) canbe determined as is known in the art, for instance based upon factorsincluding the characteristics of the crude oil and its residue, the typeof catalyst used and the coking unit operating conditions.

In certain embodiments, the additional material used, alone or incombination with one or more types of catalyst materials, compriseadsorbent material. In this regard, the disclosure of commonly ownedU.S. Pat. Nos. 9,023,192 and 9,234,146 are relevant and are incorporatedby reference herein in their entireties. For example, adsorbent materialis admixed with the coker feedstream(s) in a mixing zone, such as anin-line mixing apparatus or a mixer, to form a slurry of the cokerfeedstream(s) and adsorbent material. In certain optional embodiments, asource of catalyst material is provided along with the adsorbentmaterial in fluid or solid communication with the coking drum or vessel650 inlet. The optional catalyst material can be admixed in the samemanner as the adsorbent material, or in a different manner. Inembodiments in which optional catalyst material is used, the types andquantities of catalyst described herein for use in coking operations areapplicable.

The adsorbent material and/or heterogeneous catalyst material can beadmixed with the coker feedstream(s) with or without a dedicated mixingzone. Other embodiments that are not shown are also possible. Theadsorbent material and/or heterogeneous catalyst material can be meteredor otherwise charged separately to the coking drum or vessel 650 wherebya source of material is provided in particulate communication or fluidcommunication (in which the material is formed in a slurry) with thecoking drum or vessel 650 inlet. In further embodiments, thefractionating zone is configured for handling of adsorbent materialand/or heterogeneous catalyst material, whereby a source of material isprovided in particulate communication or fluid communication (in whichthe adsorbent material is formed in a slurry) with the fractionatingzone 660. The adsorbent material and/or heterogeneous catalyst materialis metered or otherwise charged directly to the fractionating zone 660so that a coker recycle, bottoms stream 646, contains the adsorbentmaterial and/or heterogeneous catalyst material, for instance similar tothe process that is disclosed in commonly owned U.S. Pat. No. 9,023,192,which is incorporated by reference herein in its entirety. Coke 624,which contains adsorbent material that has adsorbed undesirablecontaminants and/or heterogeneous catalyst material, is recovered fromthe coking drum or vessel 650.

The use of adsorbent material increases the quality of the thermallycracked distillates by removing some of the undesirable contaminants,for instance by selectively adsorbing sulfur- and/or nitrogen-containingcompounds. Handling of adsorbent material that has adsorbed undesirablecontaminants, and/or heterogeneous catalyst material, largely depends onthe type of coker unit deployed. For instance, in delayed coker units,the adsorbent material and/or heterogeneous catalyst material isdeposited with the coke on the inside surface of the coking drum(s). Ina fluid coking process, the adsorbent material and/or heterogeneouscatalyst material can pass with the coke particles that are discharged.

Effective adsorbent materials are selected from the group consisting ofsilica, alumina, silica-alumina, titania-silica, molecular sieves,silica gel, activated carbon, activated alumina, silica-alumina gel,zinc oxide, clays (for instance, attapulgus clay), fresh catalystmaterials (including zeolitic catalytic materials), spent catalystmaterials (including zeolitic catalytic materials), regenerated catalystmaterials (including zeolitic catalytic materials), and combinationsthereof. In certain embodiments adsorbent material comprises activatedcarbon, clays, or mixtures thereof. The material is provided inparticulate form of suitable dimension, such as granules, extrudates,tablets, or pellets, may be formed into various shapes such as spheres,cylinders, trilobes, quadrilobes or natural shapes, possess averageparticle diameters (mm) of about 0.01-4.0, 0.1-4.0, or 0.2-4.0, poresizes (nm) of about 1-5,000 or 5-5,000, possess pore volumes (cc/g) ofabout 0.08-1.2, 0.3-1.2 or 0.5-1.2, in certain embodiments at least 1.0,and possess a surface area of at least about 100 m²/g. The quantity(weight basis, hydrocarbon to adsorbent) of the solid adsorbent materialused in the embodiments herein is about 1000:1-3:1, 200:1-3-1,100:1-3:1, 50:1-3:1, 20:1-3:1, 1000:1-3:1, 200:1-8:1, 100:1-8:1,50:1-8:1, 20:1-8:1, 1000:1-3:1, 200:1-10:1, 100:1-10:1, 50:1-10:1 or20:1-10:1.

The fractionating zone, such as 460, 560 or 660 described herein,includes design features to enable separation of cracker products fromthe coking drums/vessels, including a coker distillate stream that isrecovered and the coker gas oil stream, and in certain embodiments acoker recycle stream. Components of the fractionating zone that are notshown but which are well-known can include feed/product and pump-aroundheat exchangers, charge heater(s), product strippers, cooling systems,hot and cold overhead drum systems including re-contactors and off-gascompressors, and units for water washing of overhead condensing systems.Steam is typically injected to prevent cracking of heated feed. Incertain embodiments, one or more flash vessels can be used as thefractionating zone. For instance, a first flash vessel can separategases, and in certain embodiments all or a portion of a coker distillatestream, and a second flash vessel to separate a coker gas oil stream andthe hydroprocessing feed and the coker recycle stream. In certainembodiments, in which a source of additional material is used and isintegrated in the fractionator so that the coker recycle stream containsthe additional material, the fractionator includes appropriate designfeatures.

The feeds to the fractionating zone, the coker liquid and gas stream456, 556 or 656, can be introduced at different locations in the columnsas is known. The effluents shown in the figures include the thermallycracked product streams 422, 522 or 622, or a first coker thermallycracked distillate stream 452, 552 or 652 and a second thermally crackedproduct streams 422, 522 or 622. Other streams not shown can includelight products and coker recycle. The light product stream typicallyincludes gases H₂, H₂S, NH₃ and C₁-C₄ hydrocarbons. In certainembodiments the light product stream also includes hydrocarbons at orbelow the naphtha or light naphtha range, for instance, discharged asoverhead gases and condensed in a separate vessel. A bottoms stream canbe used as a coker recycle stream, and can correspond to that of aconventional vacuum residue (for instance, having an initial boilingpoint in the range of about 510-565° C.). In certain embodiments thecoker recycle stream can include lower boiling hydrocarbons, such asthose in the heavy coker gas oil range or above, in certain embodimentshaving an initial boiling point in the range of about 450-510, 470-510or 482-510° C.

In certain embodiments, the feedstock to the delayed coker is mixed withhydrogen in a mixing zone, in certain embodiments an excess of hydrogengas. A portion of the hydrogen gas is mixed with the feedstock toproduce a hydrogen-enriched liquid hydrocarbon feedstock. Thishydrogen-enriched liquid hydrocarbon feedstock and undissolved hydrogencan be supplied to a flashing zone in which at least a portion ofundissolved hydrogen is flashed, and the hydrogen is recovered andrecycled. The hydrogen-enriched liquid hydrocarbon feedstock from theflashing zone is supplied as a feed stream to the delayed coker reactionzone, for instance coker drums. The liquid product stream that isrecovered from the reactor is further processed and/or recovered asprovided here.

The feed to the delayed coker are shown and described as thehydrocracker bottoms fraction (streams 116, 216, 316, 416, 516 and/or616 above), alone or in combination with one or more additionalfeedstocks (streams 148, 248, 348, 448, 548 and/or 648 above). Theadditional feedstock can be co-processed along with the hydrocrackingunit bottoms in the coking zone without treatment; alternatively, theadditional feedstock can be subjected to a suitable pretreatment in aresidue treatment zone. The quantity of additional feedstock can be suchthat 0-99, 10-99, 25-99, 50-99, 0-90, 10-90, 25-90, 50-90, 0-75, 10-75,25-75 or 50-75 wt % of the total feed to the coking zone is obtainedfrom the additional feedstock. The additional feedstock can be selectedfrom the group consisting of atmospheric residue, vacuum residue,deasphalted oil, demetallized oil, other heavy oil fractions, andcombinations thereof, and can be derived from crude oil, bitumens, oilsand, shale oil, coal oils or biomass oils. In certain embodiments anadditional feedstock can have an initial boiling point corresponding tothat of VGO described herein, an end point based on the characteristicsof the heavy oil fraction. In further embodiments an additionalfeedstock can have an initial boiling point of about 425-565, 450-565,425-540, 450-540, 425-530, 450-530, 425-510 or 450-510° C., in certainembodiments about 425, 450 or 475° C., and an end point based on thecharacteristics of the heavy oil fraction.

In certain embodiments, all or a portion of the additional feedstock canbe processed in a residue treatment zone. Treatment of the additionalfeedstock can be to any degree, depending on various factors includingthe desired coker liquid and gas product quantity/quality, the desiredcoke quantity/quality, the type and capacity of the coker unit and theoperating conditions.

In certain embodiments, the residue treatment zone produces a treatedadditional feedstock that, when combined with the hydrocracker bottomsfraction, produces a coker feedstock characterized by a S content ofgenerally less than about 7.5, 3.5, 1.0 or 0.5 wt %, in certainembodiments 0.2-7.5, 0.2-3.5, 0.2-0.5, 1.0-7.5, 1.0-3.5 or 3.5-7.5 wt %;and a metals content of less than about 700, 400 or 100 ppmw, Suchlevels enable recovery of high quality petroleum green coke when thehydrocracker bottoms fraction and the suitably treated additionalfeedstock is thermally cracked. The recovered high quality petroleumgreen coke can be used as low S and metal content fuel grade coke,and/or as a raw material for production of low S and metal contentmarketable grades of coke including anode grade coke (sponge) and/orelectrode grade coke (needle). Table 2 shows the properties of thesetypes of coke. In accordance with certain embodiments of the processherein, calcination of the petroleum green coke recovered from thecoking drums produces sponge and/or needle grade coke, for instance,suitable for use in the aluminum and steel industries. Calcination iscommonly known and occurs by thermal treatment to remove moisture andreduce the volatile combustible matter.

The levels of the S and metals in the total feed to the coking zone isto be considered when determining whether such high quality petroleumcoke product can be obtained. The hydrocracker bottoms fraction from theintegrated hydrocracking operation generally has sufficiently low S andmetals content. Therefore, additional feedstocks that would otherwise beunsuitable alone for production of high quality petroleum coke product,even after some degree of treatment, can be used in combination with thehydrocracker bottoms fraction to provide a total coker feed thatpossesses metals and S content compatible with the desired coke quality,such as the types of coke having properties set forth in Table 2.

TABLE 2 Calcined Calcined Fuel Sponge Needle Property Units Coke CokeCoke Bulk Density Kg/m³ 880 720-800 670-720 S W % (max) 3.5-7.5 1.0-3.50.2-0.5 N ppmw (max) 6,000 — 50 Ni ppmw (max) 500 200 7 V ppmw 150 350 —Volatile W % (max) 12 0.5 0.5 Combustible Material Ash Content W % (max)0.35 0.40 0.1 Moisture Content W % (max)  8-12 0.3 0.1 Hardgrove W %35-70  60-100 Grindability Index (HGI) Coefficient of ° C. — — 1-5thermal expansion, E + 7

As used herein, “high quality petroleum green coke” refers to petroleumgreen coke recovered from a coker unit that when calcined, possesses theproperties as in Table 2, in certain embodiments possessing theproperties in Table 2 concerning calcined sponge coke or calcined needlecoke.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock comprises residue hydrocracking, in which theadditional feedstock is treated in the presence of effectivehydrotreating catalyst and an effective amount of hydrogen obtained fromrecycle within the residue hydroprocessing zone and from make-uphydrogen. A residue hydrotreating zone generally includes one or moreinlets in fluid communication with a source of the additional feedstockand a source of hydrogen gas (including recycle and make-up hydrogen).One or more outlets of the residue hydrotreating reaction zone thatdischarge a hydrotreated residue is in fluid communication with one ormore inlets of the coking zone, for instance via the coking furnace,directly to the coking drum or vessel if the temperature is sufficient,or the coking fractionator. In certain embodiments, one or more highpressure and low pressure separation stages are provided between theresidue hydrotreating zone and the coking zone. In certain embodimentsthe residue hydrocracker a conversion of up to about 50 wt %. Inaddition to or alternatively, a stripper and/or a fractionator can beused between the residue hydrotreater and the coking zone.

The additional feedstock stream and a hydrogen stream are charged to thehydrotreating reaction zone. The hydrogen stream contains an effectivequantity of hydrogen to support the requisite degree of hydrotreating,feed type, and other factors, include recycle hydrogen from optional gasseparation subsystems associated with the residue hydrotreating reactionzone and make-up hydrogen. In certain embodiments, a reaction zone cancontain multiple catalyst beds and can receive one or more quenchhydrogen streams between the beds.

The residue hydrotreating reaction zone for treatment of the additionalfeedstock, prior to coking, can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement, and is operatedunder conditions typically effective for atmospheric or vacuum residuehydrotreating, the particular type of reactor, the feed characteristics,the desired product slate and the catalyst selection. For instance,these conditions can include a reaction temperature (° C.) in the rangeof from about 330-520, 330-475, 330-450, 380-520, 380-475 or 380-450; areaction pressure (bars) in the range of from about 90-300, 90-250,90-200, 125-300, 125-250, 125-200, 140-300, 140-250 or 140-200; ahydrogen feed rate (SL/L) of up to about 670, 625, 610, 525 or 510, incertain embodiments from about 445-475, 445-510, 445-625, 500-525,510-550, 500-610, 500-665 or 500-545; and a feed rate liquid hourlyspace velocity (h⁻¹) in the range of from about 0.1-4, 0.3-1.5, 0.3-2.5,1-3 or 1-4.

An effective quantity of catalyst is provided for hydrotreatment of theadditional feedstock, including those possessing hydrotreatingfunctionality, for hydrodemetallization, hydrodesulfurization andhydrodenitrification. Such catalysts generally contain one or moreactive metal component of metals or metal compounds (oxides or sulfides)selected from the Periodic Table of the Elements IUPAC Groups 6, 7, 8, 9and 10. In certain embodiments, the active metal component is one ormore of Co, Ni, W and Mo. The active metal component is typicallydeposited or otherwise incorporated on a support, such as amorphousalumina, amorphous silica alumina, zeolites, or combinations thereof. Incertain embodiments, the catalyst used for hydrotreatment of theadditional feedstock includes one or more beds selected from Co/Mo,Ni/Mo, Ni/W, and Co/Ni/Mo. Combinations of one or more beds of Co/Mo,Ni/Mo, Ni/W and Co/Ni/Mo, can also be used. The combinations can becomposed of different particles containing a single active metalspecies, or particles containing multiple active species. In certainembodiments, a combination of Co/Mo catalyst and Ni/Mo catalyst areeffective for hydrodemetallization, hydrodesulfurization andhydrodenitrification. One or more series of reactors can be provided,with different catalysts in the different reactors of each series. Theresidue hydrotreating catalyst material is provided in particulate formof suitable dimension, such as granules, extrudates, tablets, orpellets, may be formed into various shapes such as spheres, cylinders,trilobes, quadrilobes or natural shapes, possess average particlediameters (mm) of about 0.01-4.0, 0.1-4.0, or 0.2-4.0, pore sizes (nm)of about 1-5,000 or 5-5,000, possess pore volumes (cc/g) of about0.08-1.2, 0.3-1.2 or 0.5-1.2, in certain embodiments at least 1.0, andpossess a surface area of at least about 100 m²/g.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock comprises solvent deasphalting. Solventdeasphalting operations are well-known processes in which suitablesolvent is used to precipitate asphaltenes from the feed. The solventdeasphalting process produces a low contaminant and reduced asphaltenesproduct, known conventionally as deasphalted oil (DAO). The solventdeasphalting process is usually carried out with paraffinic C₃-C₇solvents and occurs at or below the critical temperature of the solvent.In general, in a solvent deasphalting zone, a feed is mixed with solventso that the DAO is solubilized in the solvent. The insoluble pitchprecipitates out of the mixed solution. Separation of the DAO phase(solvent-DAO mixture) and the asphalt/pitch phase typically occurs inone or more vessels or extractors designed to efficiently separate thetwo phases and minimize contaminant entrainment in the DAO phase. TheDAO phase is then heated to conditions at which the solvent becomessupercritical. In typical solvent deasphalting processed, separation ofthe solvent and DAO is facilitated in a DAO separator. Any entrainedsolvent in the DAO phase and the pitch phase is stripped out, typicallywith a low pressure steam stripping apparatus. Recovered solvent iscondensed and combined with solvent recovered under high pressure fromthe DAO separator. The solvent is then recycled back to be mixed withthe feed.

The asphalt phase contains a majority of the process reject materialsfrom the charge, i.e., metals, asphaltenes, Conradson carbon, and isalso rich in aromatic compounds and asphaltenes. In addition to thesolvent deasphalting operations described herein, other solventdeasphalting operations, although less common, are suitable. Forinstance, a three-product unit, in which resin, DAO and pitch can berecovered, can be used, where a range of bitumens can be manufacturedfrom various resin/pitch blends. Furthermore, although two extractionstages are described below, a single extraction stage can be effectiveto treat the additional feedstock, depending on the necessary degree oftreatment.

Solvent deasphalting is typically carried-out in liquid phase thus thetemperature and pressure are set accordingly. There are commonly twostages for phase separation in solvent deasphalting. In a firstseparation stage, the temperature is maintained at a lower level thanthe temperature in the second stage to separate the bulk of theasphaltenes. The second stage temperature is selected to control thefinal DAO quality and quantity. Excessive temperature levels will resultin a decrease in DAO yield, but the DAO will be lighter, less viscous,and contain less metals, asphaltenes, S, and N. Insufficient temperaturelevels have the opposite effect such that the DAO yield increases butthe product quality is reduced. Operating conditions for solventdeasphalting units are generally based on a specific solvent and chargestock to produce a DAO of a specified yield and quality. Extractiontemperature is generally fixed for a given solvent, with smalladjustments to maintain the DAO quality. The composition of the solventis also an important process variable. The solubility of the solventincreases with increasing critical temperature, such thatC₃<iC₄<nC₄<iC₅, i.e., the solubility of iC₅ is greater than that of nC₄,the solubility of nC₄ is greater than that of iC₄, the solubility of iC₄is greater than that of C₃. An increase in critical temperature of thesolvent increases the DAO yield. However, solvents having highercritical temperatures afford less selectivity resulting in lower DAOquality. Solvent deasphalting units are operated at pressures that arehigh enough to maintain the solvent in the liquid phase, and depend onthe deasphalting solvent composition. The volumetric ratio of thesolvent to the solvent deasphalting unit charge is also a factor inselectivity, and to a lesser degree, on the DAO yield. A higher ratioresults in a higher quality of the DAO for a fixed deasphalted yield.Selection of the solvent is also considered in establishing operationalsolvent-to-oil ratios; generally the solvent-to-oil ratio decreases asthe critical solvent temperature increases.

In one embodiment, a solvent deasphalting zone generally includes afirst phase separation zone and a second phase separation zone. Thefirst phase separation zone includes one or more inlets in fluidcommunication with a source of the additional feedstock, and in fluidcommunication with a source of paraffinic hydrocarbon as deasphaltingsolvent, and includes, for example, one or more primary settler vesselssuitable to accommodate the mixture of the additional feedstock andsolvent. The first phase separation zone generally includes necessarycomponents to operate at suitable temperature and pressure conditions,such as below the critical temperature and pressure of the solvent. Thefirst phase separation zone also includes one or more outlets fordischarging an asphalt phase, and one or more outlets for discharging areduced asphalt content phase, which is the primary DAO phase. Theoutlet(s) discharging the asphalt phase are typically in fluidcommunication with a solvent-asphalt separation zone for recovery ofsolvent contained in the asphalt phase from the first phase separationzone.

The second phase separation zone includes one or more inlets in fluidcommunication with the reduced asphalt content phase outlet from thefirst phase separation zone, and includes, for example, one or moresecondary settler vessels suitable to accommodate the feed. The secondphase separation zone generally includes necessary components to operateat temperature and pressure conditions below critical properties of thesolvent. The second phase separation zone includes one or more outletsfor discharging an asphalt phase. In certain embodiments the outlet fordischarging the asphalt phase is in fluid communication with thesolvent-asphalt separation zone for recovery of solvent. In furtherembodiments the outlet discharging the asphalt phase is in fluidcommunication with an inlet of first phase separation zone via a recyclestream.

The second phase separation zone also includes one or more outlets fordischarging a reduced asphalt content phase stream, which is thesecondary DAO phase. The secondary DAO phase is typically in fluidcommunication one or more inlets of a solvent-DAO separation zone. Thesolvent-DAO separation zone contains one or more flash vessels orfractionation units operable to separate solvent and DAO. The separationzone includes one or more outlets for discharging a solvent stream,which is in fluid communication with one or more inlets of the firstphase separation zone, and one or more outlets for discharging DAO. Theoutlet discharging DAO is in fluid communication with the coking zone asdescribed herein, as the additional feedstock that has been subjected topretreatment.

The solvent-asphalt separation zone is used and includes one or moreinlets in fluid communication with the outlet(s) discharging asphaltstreams. The separation zone contains one or more flash vessels orfractionation units operable to separate solvent and asphalticmaterials, and can include, for instance, necessary heat exchangers toincrease the temperature before a separation vessel. The solvent-asphaltseparation zone also includes one or more outlets for discharging arecycle solvent stream, which is in fluid communication with the firstphase separation zone, and an outlet for discharging an asphalt stream.In certain embodiments, the outlet discharging the asphalt stream is influid communication with a gasification zone or an asphalt pool.

The solvent stream is derived from one or more solvent sourcescomprising an integrated process solvent stream such as light naphthafrom the hydrocracker products or the coker light products, recyclesolvent stream from the solvent-DAO separation zone and/or thesolvent-asphalt separation zone, and/or make-up solvent which can bethose used in typical solvent deasphalting processes such as C₃-C₇paraffinic hydrocarbons. The following Table 3 provides criticaltemperature and pressure data for C₃-C₇ paraffinic solvents.

TABLE 3 Carbon Number Temperature, ° C. Pressure, bar C₃ 97 42.5 C₄ 15238.0 C₅ 197 34.0 C₆ 235 30.0 C₇ 267 27.5

In operation of a deasphalting process herein, the mixture of theadditional feedstock and solvent is passed to first phase separationzone in which phase separation occurs. The additional feedstock andsolvent are mixed, for example using an in-line mixer or a separatemixing vessel. Mixing can occur as part of the first phase separationzone or prior to entering the first phase separation zone. The firstphase separation zone serves as the first stage for the extraction ofDAO from the feedstock. The two phases formed in the first phaseseparation zone are an asphalt phase and a primary DAO phase. Thetemperature at which the contents of the first phase separation zone aremaintained is sufficiently low to maximize recovery of the DAO from thefeedstock. In certain embodiments conditions in the first phaseseparation zone are maintained below the critical temperature andpressure of the solvent. In general, components with a higher degree ofsolubility in the solvent will pass with the primary DAO phase. Theprimary DAO phase includes a major portion of the solvent, a minorportion of the asphalt content of the feedstock and a major portion ofthe DAO content of the feedstock. The asphalt phase generally contains aminor portion of the solvent and is discharged, typically from thebottom of the vessel. In the second phase separation zone, the DAO phasefrom the first phase separation zone, which contains some asphalt,enters a separation vessel, for example, a secondary settler. An asphaltphase separates and forms at the bottom of the secondary settler that,due to increased temperature, is approaching the critical temperature ofthe solvent. The rejected asphalt from the secondary settler contains arelatively small amount of solvent and DAO. In certain embodiments allor any portion of the asphalt phase is recycled back to first phaseseparation zone for the recovery of remaining DAO. In other embodimentsall or any portion of the asphalt phase from the secondary settler ismixed with the asphalt stream from the primary settler. All or anyportion of the asphalt stream from first phase separation zone, and/orthe asphalt stream from second phase separation zone can be charged to asolvent-asphalt separation zone. The asphalt can optionally be heated inheater before being passed to the inlet of the solvent-asphaltseparation zone. Additional solvent is flashed from the solvent-asphaltseparation zone and recycled to the first phase separation zone. Abottoms asphalt stream from the solvent-asphalt separation zone canoptionally be passed to a steam stripper for steam stripping of theasphalt as conventionally known to recover a steam stripped asphaltphase, and a steam/solvent mixture for solvent recovery and recycle. Theasphalt stream, containing precipitated asphaltenes, is removed from thesolvent deasphalting unit on regular basis to facilitate thedeasphalting process.

The secondary DAO phase is passed to the solvent-DAO separation zone torecover solvent for recycle. Solvent is flashed and discharged forrecycle to the first phase separation zone in certain embodiments in acontinuous operation. A DAO stream from the separation zone can bepassed to the coking zone as the treated additional feedstock, or canoptionally be subjected to steam stripping as is conventionally known torecover a steam stripped DAO as the as the treated additional feedstock,and a steam/solvent mixture for solvent recovery and recycle.

In certain embodiments an enhanced solvent deasphalting process can beused, as described herein and in U.S. Pat. Nos. 7,566,394,7,799,211/8,986,622, or 7,763,163/7,867,381, which are commonly ownedand incorporated by reference herein in their entireties.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock comprises an enhanced solvent deasphalting zone, inwhich adsorbent material is included in the first phase separation zone.The enhanced solvent deasphalting zone generally includes a mixing zone,a first phase separation zone, an adsorbent stripping zone, asolvent-asphalt separation zone, and a second phase separation zone. Forinstance, a similar enhanced solvent deasphalting process is describedin commonly owned U.S. Pat. No. 7,566,394, which is incorporated byreference herein in its entirety.

The mixing zone includes one or more inlets in fluid communication witha source of the additional feedstock, a source of solid adsorbentmaterial, and a source of deasphalting solvent. In certain embodimentsthe mixing zone is equipped with suitable mixing apparatus such asrotary stirring blades or paddles, which provide a gentle, but thoroughmixing of the contents. The mixing zone can be operated as an ebullatedbed, fixed-bed, tubular or continuous stirred-tank reactor. The mixingzone includes one or more outlets for discharging a slurry containingthe mixture of the feed, deasphalting solvent and adsorbent material. Incertain embodiments mixing can occur in one or more in-line apparatus sothat the slurry is formed and send to the first phase separation zone.

The slurry outlet is in fluid communication with one or more inlets ofthe first phase separation zone. The first phase separation zoneincludes, for example, one or more primary settler vessels suitable toaccommodate the mixture of the additional feedstock, deasphaltingsolvent and adsorbent material. The first phase separation zone can besimilar to that used in typical solvent deasphalting described above andgenerally includes necessary components to operate at temperature andpressure conditions below the critical temperature and pressure of thedeasphalting solvent. The first phase separation zone also includes oneor more outlets for discharging a light phase stream, and one or moreoutlets for discharging a bottoms phase stream.

A second phase separation zone includes one or more inlets in fluidcommunication with the light phase stream outlet for separation ofdeasphalting solvent from DAO. The second phase separation zoneincludes, for example, one or more settler vessels suitable toaccommodate the mixture of DAO and deasphalting solvent. The secondphase separation zone can be similar to that used in typical solventdeasphalting and generally includes necessary components to operate atsuitable temperature and pressure conditions, such as below the criticalproperties of the deasphalting solvent. The second phase separation zoneincludes one or more outlets for discharging a recycle deasphaltingsolvent stream, and one or more outlets for discharging a DAO stream.The recycle deasphalting solvent stream outlet is in fluid communicationwith inlet(s) to the mixing zone.

The bottoms phase stream outlet, and a source of stripping solvent, arein fluid communication with one or more inlets of the adsorbentstripping zone to separate and clean the adsorbent material. Theadsorbent stripping zone can include one or more filtration vessels, andincludes one or more outlets for discharging stripped adsorbent materialand one or more outlets for discharging an asphalt stream. The adsorbentmaterial outlet is in fluid communication with an inlet of the mixingzone to recycle adsorbent material. A portion of the adsorbent materialcan also be discharged in a continuous, periodic or as-needed manner,for instance, as spent adsorbent material. The adsorbent stripping zonealso includes one or more outlets for discharging a strippingsolvent-asphalt mixture that is in fluid communication with an inlet ofthe solvent-asphalt separation zone, such as a flash vessel orfractionator, to separate stripping solvent. The solvent-asphaltseparation zone further includes outlets for discharging an asphaltstream and a recycle stripping solvent stream. The recycle strippingsolvent stream outlet is in fluid communication with inlet(s) of theadsorbent stripping zone. In certain embodiments, the asphalt streamoutlets and/or the adsorbent material outlet (via the spent adsorbent)are in fluid communication with a gasification zone or an asphalt pool.

The deasphalting solvent stream is derived from one or more solventsources comprising an integrated process solvent stream such as lightnaphtha from the hydrocracker products or the coker light products, arecycle deasphalting solvent stream from the second phase separationzone, and in certain embodiments make-up deasphalting solvent. Make-updeasphalting solvent can be a solvent from another source that is usedin typical solvent deasphalting processes as described herein. Thestripping solvent stream is derived from one or more solvent sourcescomprising an integrated process solvent stream such as light naphthafrom the hydrocracker products or the coker light products, a recyclestripping solvent stream from the solvent-asphalt separation zone, andin certain embodiments make-up stripping solvent.

In operation of the enhanced solvent deasphalting zone in whichadsorbent material is included in the first phase separation zone, theadditional feedstock, adsorbent material, and the deasphalting solventstream are charged to the mixing zone and mixed to provide the slurry.The rate of agitation for a given vessel and mixture of adsorbent,solvent and feedstock is selected so that there is minimal, if any,attrition of the adsorbent granules or particles. For example, mixingcan be carried out for 30 to 150 minutes. In addition, the additionalfeedstock, adsorbent material, and the deasphalting solvent stream canbe mixed in an in-line mixer to produce the slurry. The slurry is passedto the first phase separation zone, which operates under temperature andpressure conditions effective to facilitate separation of the feedmixture into an upper layer comprising light and less polar fractionsthat are removed as the light phase stream, and the bottoms phase streamcomprising asphaltenes and the solid adsorbent. In certain embodiments,vertical flash drum can be utilized for this separation step. Conditionsin the mixing vessel and first phase separation zone are generallymaintained below the critical temperature and pressure of thedeasphalting solvent as described above in the embodiments usingconventional solvent deasphalting. The light phase stream is passed tothe second separation vessel which is maintained at an effectivetemperature and pressure to separate deasphalting solvent from the DAO,such as between the boiling and critical temperature of the solvent, andunder a pressure of for instance between about 1-3 bars. Thedeasphalting solvent stream is recovered and recycled to the mixingzone, in certain embodiments in a continuous operation. The DAO streamfrom the second separation zone can be passed to the coking zone as thetreated additional feedstock, or can optionally be subjected to steamstripping as is conventionally known to recover a steam stripped DAO asthe as the treated additional feedstock, and a steam/solvent mixture forsolvent recovery and recycle.

The asphalt and adsorbent slurry are mixed with a stripping solventstream in an adsorbent stripping zone to separate and clean theadsorbent material by desorption. In certain embodiments, the adsorbentslurry and asphalt mixture is washed with two or more aliquots of thestripping solvent in the adsorbent stripping zone in order to dissolveand remove the adsorbed process reject materials. The clean solidadsorbent stream is recovered, and all or a portion is recycled to themixing zone. A portion of the adsorbent material can also be dischargedin a continuous, periodic or as-needed manner, for instance, as spentadsorbent material. An asphalt stream is recovered, and containsasphaltenes and process reject materials that were desorbed from theadsorbent. A solvent-asphalt mixture is withdrawn from the adsorbentstripping zone and is it is sent to a separation zone to discharge anasphalt stream and a clean stripping solvent stream which can berecycled to the adsorbent stripping zone, in certain embodiments in acontinuous operation.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock comprises an enhanced solvent deasphalting zone, inwhich adsorbent material is included in the second phase separationzone. The enhanced solvent deasphalting zone generally includes a firstphase separation zone, a second phase separation zone, an adsorbentstripping zone and a solvent-DAO separation zone. For instance, asimilar enhanced solvent deasphalting process is described in commonlyowned U.S. Pat. No. 7,566,394, which is incorporated by reference hereinin its entirety.

The first phase separation zone includes one or more inlets in fluidcommunication with a source of the additional feedstock, and a source ofdeasphalting solvent. The first phase separation zone includes, forexample, one or more primary settler vessels suitable to accommodate themixture of the additional feedstock and deasphalting solvent. The firstphase separation zone can be similar to that used in typical solventdeasphalting described above and generally includes necessary componentsto operate at temperature and pressure conditions below the criticaltemperature and pressure of the deasphalting solvent. The first phaseseparation zone also includes one or more outlets for discharging alight phase stream and one or more outlets for discharging a bottomsphase stream.

A second phase separation zone includes one or more inlets in fluidcommunication with the light phase stream outlet and a source of solidadsorbent material. The second phase separation zone provides contactand residence time with the adsorbent material, and facilitatesseparation of deasphalting solvent from DAO. The second phase separationzone includes, for example, one or more settler vessels suitable toaccommodate the mixture of DAO, deasphalting solvent and adsorbentmaterial. The second phase separation zone can be similar to that usedin typical solvent deasphalting described above and generally includesnecessary components to operate at suitable temperature and pressureconditions, such as below the critical properties of the deasphaltingsolvent. The second phase separation zone includes one or more outletsfor discharging a recycle deasphalting solvent stream, and one or moreoutlets for discharging a slurry of DAO and adsorbent material. Therecycle deasphalting solvent stream outlet is in fluid communicationwith inlet(s) to the first phase separation zone.

The slurry outlet, and a source of stripping solvent, are in fluidcommunication with one or more inlets of the adsorbent stripping zone toseparate and clean the adsorbent material. The adsorbent stripping zonecan include one or more filtration vessels and includes one or moreoutlets for discharging stripped adsorbent material and one or moreoutlets for discharging an asphalt stream. The adsorbent material outletis in fluid communication with an inlet of the second phase separationzone or associated mixing zone to recycle adsorbent material. A portionof the adsorbent material can also be discharged in a continuous,periodic or as-needed manner, for instance, as spent adsorbent material.The adsorbent stripping zone also includes one or more outlets fordischarging a solvent-DAO stream that is in fluid communication with aninlet of a solvent-DAO separation zone, such as a flash vessel orfractionator, to separate stripping solvent. The solvent-DAO separationzone includes one or more outlets for discharging a recycle strippingsolvent stream, one or more outlets for discharging a DAO stream, andone or more outlets for discharging an asphalt stream. The recyclestripping solvent stream outlet is in fluid communication with inlet(s)of the adsorbent stripping zone. In certain embodiments, the asphaltoutlets and/or the adsorbent material outlet (via the spent adsorbent)are in fluid communication with a gasification zone or an asphalt pool.

The deasphalting solvent stream is derived from one or more solventsources comprising an integrated process solvent stream such as lightnaphtha from the hydrocracker products or the coker light products, arecycle deasphalting solvent stream from the second phase separationzone, and in certain embodiments make-up deasphalting solvent. Make-updeasphalting solvent can be a solvent from another source that is usedin typical solvent deasphalting processes as described herein. Thestripping solvent stream is derived from one or more solvent sourcescomprising an integrated process solvent stream such as light naphthafrom the hydrocracker products or the coker light products, a recyclestripping solvent stream from the solvent-asphalt separation zone, andin certain embodiments make-up stripping solvent.

In operation of the enhanced solvent deasphalting zone in whichadsorbent material is included in the second phase separation zone, theadditional feedstock and the deasphalting solvent stream are charged tofirst phase separation zone. The first phase separation zone operatesunder temperature and pressure conditions effective to facilitateseparation of the feed mixture into an upper layer comprising light andless polar fractions that are removed as the light phase stream, and thebottoms phase stream containing asphaltenes. Conditions in the firstseparation vessel are maintained below the critical temperature andpressure of the deasphalting solvent, as described above in theembodiment using conventional solvent deasphalting. The light phasestream is mixed with an effective quantity of solid adsorbent material,including fresh and recycled adsorbent material, for instance using anin-line mixing apparatus and/or a separate mixing zone, to produce aslurry of DAO, deasphalting solvent, and solid adsorbent material. Theslurry is passed to the second phase separation zone and is maintainedat an effective temperature and pressure to separate solvent from theDAO, such as between the boiling and critical temperature of thedeasphalting solvent, and under a pressure of between 1-3 bars. Inaddition, the mixture is maintained in the second phase separation zonefor a time sufficient to adsorb on the adsorbent material any remainingasphaltenes. The deasphalting solvent is separated from the DAO andadsorbent material, and the deasphalting solvent is recovered andrecycled to the first phase separation zone. The slurry of DAO andadsorbent from the second phase separation zone is mixed with thestripping solvent stream in the adsorbent stripping zone to separate andclean the adsorbent material. In certain embodiments, the adsorbentslurry and DAO is washed with two or more aliquots of the strippingsolvent in the adsorbent stripping zone in order to dissolve and removethe adsorbed compounds. The clean solid adsorbent is recovered, and allor a portion is recycled to the second phase separation zone. A portionof the adsorbent material can also be discharged in a continuous,periodic or as-needed manner, for instance, as spent adsorbent material.A stripping solvent-DAO mixture is withdrawn from the adsorbentstripping zone, and an asphalt stream is also discharged, which containsasphaltenes and process reject materials that were desorbed from theadsorbent. The stripping solvent-DAO mixture is sent to solvent-DAOseparation zone, including an inlet for receiving the strippingsolvent-DAO mixture, and outlets for discharging an asphalt stream, aclean solvent stream which is recycled to adsorbent stripping zone, anda DAO stream.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock includes an oxidation treatment step. Theadditional feedstock is contacted with an oxidant to produce anintermediate charge containing oxidized organosulfur compounds, andpassing that intermediate charge to any of the herein describeddeasphalting or enhanced processes. In this manner, the oxidized portionof the additional feedstock has a polarity that results in shifting tothe asphalt phase due to its insoluble nature in the deasphaltingsolvent. An example of a process and system that can be integrated inthis manner is disclosed in commonly owned U.S. Pat. No. 10,125,319,which is incorporated by reference herein in its entirety. Furthermore,integration with a coking unit to enable production of higher grades ofcoke is disclosed in commonly owned U.S. Pat. No. 9,896,629, which isincorporated by reference herein in its entirety. For example, anadditional feedstock is introduced an oxidizer column vessel, typicallyafter passage through one or more heat exchangers, and optionally in thepresence of a homogeneous catalyst. Gaseous oxidant is typicallycompressed and routed to distributors in the oxidizer column. Theoxidized additional feedstock is passed to any of the herein describeddeasphalting processed including with or without adsorbent material. Thegaseous oxidant can be air, oxygen, nitrous oxide or ozone. The oxygento oil ratio is in the range of about 1-50, 1-20, 3-50 or 3020 V:V %, orequivalent ratio for other gaseous oxidants. The oxidizing unit operatesat a temperature range of about 100-300, 150-300, 100-200 or 150-200° C.at the inlet, and about 250-300° C. in the oxidation zone, and at apressure level ranging from about ambient to 60 bars, or ambient to 30bars. Catalyst that optionally can be added to the oxidation step canbe, for example homogeneous transition metal catalysts, active metalcomponents of which are Mo(VI), W(VI), V(V), Ti(IV), possessing highLewis acidity with weak oxidation potential.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock comprises comprise adsorptive treatment. Theadditional feedstock is treated by contacting with an effective type(s)and quantity of adsorbent material, and under effective conditions, toremove asphaltenes and other contaminants, accompanied by atmosphericand vacuum separation. The resulting mixture is then subjected toatmospheric separation to recover an atmospheric light fraction and anatmospheric heavy fraction, with the adsorbent material passing with theheavy fraction. At this stage, asphaltenes from the feed are adsorbed onand/or within the pores of the adsorbent material. The atmospheric heavyfraction is further separated in a vacuum separation zone to recovervacuum light fraction and a vacuum heavy fraction, with the adsorbentmaterial passing with the heavy fraction. The adsorbent material isregenerated using one or more internal solvent sources as describedherein, and recycled for contacting with the feed. An example of aprocess and system that can be integrated in this manner is disclosed incommonly owned U.S. Pat. Nos. 7,799,211 and 8,986,622, which areincorporated by reference herein in their entireties.

For example, an adsorptive treatment and separation zone includes amixing zone, an atmospheric separation zone, a vacuum separation zone, afiltration/regeneration zone, and a stripping solvent separation zone.The mixing zone includes one or more inlets in fluid communication withthe additional feedstock, and a source of solid adsorbent material. Themixing zone can be operated as an ebullated bed, fixed-bed, tubular orcontinuous stirred-tank reactor. In certain embodiments, the mixing zoneoperates as a mixing vessel, equipped with suitable mixing apparatussuch as rotary stirring blades or paddles, which provide a gentle, butthorough mixing of the contents. The mixing zone includes one or moreoutlets for discharging a mixture of the additional feedstock andadsorbent material. In certain embodiments, not shown, mixing can occurin one or more in-line apparatus so that the slurry is formed and sendto the atmospheric flash separation zone. The atmospheric separationzone includes one or more inlets in fluid communication with the outletdischarging the mixture/slurry of the feed and adsorbent material. Theatmospheric separation zone includes suitable flash or fractionationvessels operating generally at atmospheric conditions with one or moreoutlets for discharging an atmospheric light fraction, and one or moreoutlets for discharging an atmospheric heavy fraction which contains theadsorbent material. The vacuum separation zone includes one or moreinlets in fluid communication with the outlet discharging theatmospheric heavy fraction containing the adsorbent material. The vacuumseparation zone includes suitable flash or fractionation vesselsoperating generally at vacuum conditions with one or more outlets fordischarging a vacuum light fraction, and one or more outlets fordischarging a vacuum heavy fraction which contains the adsorbentmaterial. The outlets discharging the atmospheric light fraction and thevacuum light fraction are in fluid communication with the coking zonedescribed herein as the treated additional feedstock.

The filtration/regeneration zone includes one or more inlets in fluidcommunication with the outlet discharging the vacuum heavy fraction, andone or more inlets in fluid communication with a source of strippingsolvent. The filtration/regeneration zone can include one or morefiltration vessels for discharging regenerated adsorbent material thatis in fluid communication with the mixing zone. A portion of theadsorbent material can also be discharged in a continuous, periodic oras-needed manner, for instance, as spent adsorbent material. In certainembodiments, the spent adsorbent material outlet is in fluidcommunication with a gasification zone or an asphalt pool. In certainembodiments, parallel vessels are used so that the system is operated inswing mode. The filtration/regeneration zone also includes one or moreoutlets outlet for discharging a stream containing vacuum residue, andone or more outlets for discharging a stream containing a mixture ofasphaltenes and other process reject materials from the adsorbentmaterial. In certain embodiments the outlet discharging vacuum residueis in fluid communication with the coking zone described herein as partof the additional feedstock, or a separate unit such as a gasificationzone.

A stripping solvent separation zone includes one or more inlets in fluidcommunication with the outlet discharging a stream containing a mixtureof stripping solvent, asphaltenes and other process reject materials.The stripping solvent separation zone contains one or more flash vesselsor fractionation units operable to separate stripping solvent from themixture, and includes one or more outlets for discharging a strippingsolvent stream, which is in fluid communication with one or more inletsof the filtration/regeneration zone, and one or more outlets fordischarging asphaltenes and other process reject materials. In certainembodiments the outlet discharging asphaltenes and other process rejectmaterials is in fluid communication with a gasification zone, or anasphalt pool. In general, the stripping solvent stream is derived fromone or more solvent sources comprising an integrated process solventstream such as light naphtha from the hydrocracker products or the cokerlight products, a recycle stripping solvent stream, and in certainembodiments a make-up stripping solvent stream.

In operation of the adsorptive treatment and separation zone, theadditional feedstock and solid adsorbent material are fed to the mixingzone and mixed to form a slurry. The rate of agitation for a givenvessel and mixture of adsorbent, solvent and feedstock is selected sothat there is minimal, if any, attrition of the adsorbent granules orparticles. The solid adsorbent/crude oil slurry mixture is transferredto the atmospheric separator to separate and recover the atmosphericlight fraction. The atmospheric heavy fraction from the atmosphericseparator is sent to the vacuum separator. The vacuum light fractionstream is withdrawn from the vacuum separator and the bottoms streamcontaining vacuum flash residue and solid adsorbent are sent to theadsorbent regeneration zone. The atmospheric light fraction and thevacuum light fraction stream are passed to the coking zone as treatedadditional feedstock. Vacuum residue is withdrawn from the adsorbentregeneration zone and the bottoms are removed and separated so that thereusable regenerated adsorbents are recycled back and introduced withfresh adsorbent material and the feedstock into mixing zone. A spentportion of the adsorbent material is discharged in a continuous,periodic or as-needed manner. In certain embodiments, the adsorbentregeneration zone is operated in swing mode so that production of theregenerated absorbent is continuous; when adsorbent material oneregeneration column is spent and no longer effective for adsorption, theflow is directed to the other column. The adsorbed compounds aredesorbed in the process herein using solvent treatment, for instance, ata pressure in the range of about 1-30 bars temperature range of fromabout 20-250° C. or 20-205° C. The adsorbed compounds are desorbed witha stripping solvent to remove at least some of the process rejectmaterials so that at least a portion of the adsorbent material can berecycled. The stream containing stripping solvent and rejectedcomponents from the regeneration unit is sent to a separation zone,recovered stripping solvent is recycled back to the adsorbentregeneration zone, and rejected components are discharged.

In certain embodiments a residue treatment zone for treatment of theadditional feedstock comprises comprise adsorptive treatment. Theadditional feedstock is treated by contacting with an effective type(s)and quantity of adsorbent material, and under effective conditions, toremove asphaltenes and other contaminants, with a packed bed or slurrycolumn. The additional feedstock is passed through at least one packedbed column containing adsorbent material, or is mixed with adsorbentmaterial and passed through a slurry column. Asphaltene and othercontaminants are adsorbed. The adsorbent material is regenerated withstripping solvent and recycled for contacting with the additionalfeedstock. An example of a process and system that can be integrated inthis manner is disclosed in commonly owned U.S. Pat. Nos. 7,763,163 and7,867,381, which are incorporated by reference herein in theirentireties.

For example, an adsorptive treatment zone includes an adsorbentcontacting zone and a solvent-asphalt separation zone. The adsorbentcontacting zone contains one or more vessels which contain an effectiveof adsorbent material, and can be for example one or more packed bedcolumns. The adsorbent contacting zone generally includes one or moreinlets in fluid communication with a source of the additional feedstock,and one or more outlets for discharging an adsorbent treated stream,during an adsorption mode of operation. In addition, the adsorbentcontacting zone comprises one or more inlets in fluid communication witha source of a stripping solvent and one or more outlets for discharginga stream of stripping solvent and rejected components during adesorption mode of operation. The outlet discharging the adsorbenttreated stream is in fluid communication with the coking zone describedherein as the treated additional feedstock. The solvent-asphaltseparation zone includes one or more inlets in fluid communication withthe stream of stripping solvent and rejected components, and containsone or more flash vessels or fractionation units operable to separatesolvent and asphaltic materials, and can include, for instance,necessary heat exchangers to increase the temperature before aseparation vessel. The solvent-asphalt separation zone also includes oneor more outlets for discharging a bottoms stream containing rejectedmaterials, and one or more outlets for discharging a recycle strippingsolvent stream that is in fluid communication with the adsorbentcontacting zone during desorbing operations. In certain embodiments, thebottoms stream outlet is in fluid communication with a gasification zoneor an asphalt pool. In general, the stripping solvent stream is derivedfrom one or more solvent sources comprising an integrated processsolvent stream such as light naphtha from the hydrocracker products orthe coker light products, a recycle stripping solvent stream, and incertain embodiments a make-up stripping solvent stream.

The contacting zone operates in an adsorption mode and a desorptionmode. In the adsorption mode, the additional feedstock is passed to thecontacting zone and flows under the effect of gravity or by pressureover the adsorbent material to absorb asphaltenes and othercontaminants, and under effective conditions to adsorb at least aportion of asphaltenes and other contaminants in the feed. For instance,effective adsorption conditions include a pressure in the range of about1-30 bars and a temperature in the range of about 20-250° C. or 20-205°C. The cleaned feedstock is removed from the contacting zone and passedas treated additional feedstock to the coking zone described herein. Ina desorption mode, adsorbed asphaltenes and other contaminants areeluted with stripping solvent under effective conditions to remove atleast a portion thereof. For instance, effective desorption conditionsinclude a pressure in the range of about 1-30 bars and a temperature inthe range of about 20-250° C. or 20-205° C. The stream of strippingsolvent and rejected materials is passed to the solvent-asphaltseparation zone, and the mixture is separated, for instance by flashseparation or fractionation, into the relatively light recycle strippingsolvent stream and the relatively heavy bottoms stream which containsthe asphaltenes and other contaminants that were stripped from theadsorbent material. In certain embodiments, parallel vessels are used inthe adsorbent contacting zone and the system is operated in swing modeso that production of the cleaned feedstock can be continuous. When theadsorbent material in a first vessel becomes spent and no longereffective for adsorption, the flow of the feedstream is directed toanother column containing fresh or regenerated adsorbent material. Thefeedstream enters the top of one of the columns and flows under theeffect of gravity or by pressure over the adsorbent material to absorbasphaltenes and other contaminants. The cleaned feedstock is removedfrom the bottom of that column. Concurrently, stripping solvent is fedto the other column to carry out desorption operations as describedabove.

In another embodiment, adsorptive treatment zone includes an adsorbentslurry contacting zone, a filtration/regeneration zone, and asolvent-asphalt separation zone. The adsorbent slurry contacting zoneincludes one or more inlets in fluid communication with a source of theadditional feedstock, and a source of adsorbent material. The adsorbentslurry contacting zone can be operated as an ebullated bed, fixed-bed,tubular or continuous stirred-tank reactor. In certain embodiments, theadsorbent slurry contacting zone operates as a mixing vessel, equippedwith suitable mixing apparatus such as rotary stirring blades orpaddles, which provide a gentle, but thorough mixing of the contents.The adsorbent slurry contacting zone includes one or more outlets fordischarging a mixture of the additional feedstock and adsorbentmaterial. In certain embodiments mixing can occur in one or more in-lineapparatus so that the slurry is formed and sent to thefiltration/regeneration zone. The filtration/regeneration zone includesone or more inlets in fluid communication with the outlet dischargingthe mixture of the additional feedstock and adsorbent material, and oneor more inlets in fluid communication with a source of strippingsolvent. The filtration/regeneration zone includes one or morefiltration vessels and includes one or more outlets for discharging aregenerated adsorbent material that is in fluid communication with theadsorbent slurry contacting zone. A portion of the adsorbent materialcan also be discharged in a continuous, periodic or as-needed manner,for instance, as spent adsorbent material. In certain embodiments, thespent adsorbent material outlet is in fluid communication with agasification zone or an asphalt pool. The filtration/regeneration zonealso includes one or more outlets for discharging a stream containingadsorbent treated additional feedstock, and one or more outlets fordischarging a stream containing a mixture of solvent, asphaltenes andother process reject materials from the adsorbent material. The outletdischarging the adsorbent treated additional feedstock is in fluidcommunication with the coking zone described herein as the treatedadditional feedstock. The solvent-asphalt separation zone includes oneor more inlets in fluid communication with the stream of strippingsolvent and rejected components, and contains one or more flash vesselsor fractionation units operable to separate solvent and asphalticmaterials, and can include, for instance, necessary heat exchangers toincrease the temperature before a separation vessel. The solvent-asphaltseparation zone also includes one or more outlets for discharging abottoms stream containing rejected materials, and one or more outletsfor discharging a recycle stripping solvent stream that is in fluidcommunication with the adsorbent contacting zone during desorbingoperations. In certain embodiments, the bottoms stream outlet is influid communication with a gasification zone or an asphalt pool. Ingeneral, the stripping solvent stream is derived from one or moresolvent sources comprising an integrated process solvent stream such aslight naphtha from the hydrocracker products or the coker lightproducts, a recycle stripping solvent stream, and in certain embodimentsa make-up stripping solvent stream.

In operation of the adsorptive treatment zone including an adsorbentslurry contacting zone, the additional feedstock and adsorbent materialare charged to the adsorbent slurry contacting zone under conditionseffective for adsorption of asphaltenes and other contaminants, and toprovide a slurry. The rate of agitation for a given vessel and mixtureof adsorbent and feedstock is selected so that there is minimal, if any,attrition of the adsorbent granules or particles. For example, mixingcan be carried out for 30 to 150 minutes, at a pressure in the range ofabout 1-30 bars and a temperature in the range of about 20-250° C. or20-205° C. In addition, the additional feedstock and adsorbent materialcan be mixed in an in-line mixer to produce the slurry. The slurry ispassed to the filtration/regeneration zone for contact with strippingsolvent under effective conditions to strip at least a portion of theadsorbed asphaltenes and other contaminants. The treated feedstock isremoved from the contacting zone and passed as treated additionalfeedstock to the coking zone described herein. The stream containing themixture of solvent, asphaltenes and other process reject materials ispassed to the solvent-asphalt separation zone for recovery of solvent.The mixture is separated, for instance by flash separation orfractionation, into the relatively light recycle solvent stream and therelatively heavy bottoms stream which contains the asphaltenes and othercontaminants that were stripped from the adsorbent material. Regeneratedadsorbent material is discharged and at least a portion is typicallyrecycled to the adsorbent slurry contacting zone, and spent adsorbentcan be removed.

Solid adsorbent materials or mixture of solid adsorbent materials foruse in the embodiments herein that are effective to capture asphaltenesand other contaminants include in the additional feedstock are thosethat are characterized by high surface area, large pore volumes, and awide pore diameter distribution. Types of adsorbent materials that areeffective include molecular sieves, silica gel, activated carbon,activated alumina, silica-alumina gel, zinc oxide, clays such asattapulgus clay, fresh zeolitic catalyst materials, used zeoliticcatalyst materials, spent catalysts from other refining operations, andmixtures of two or more of these materials. Effective adsorbentmaterials are provided in particulate form of suitable dimension, suchas granules, extrudates, tablets, or pellets, and may be formed intovarious shapes such as spheres, cylinders, trilobes, quadrilobes ornatural shapes. In certain embodiments, having average particlediameters (mm) in the range of from about 0.01-4.0, 0.1-4.0, or 0.2-4.0,average pore diameters (nm) in the range of from 1-5,000 or 5-5,000,pore volumes (cc/g) in the range of from about 0.08-1.2, 0.3-1.2,0.5-1.2, 0.08-0.5, 0.1-0.5, or 0.3-0.5, and a surface area of at leastabout 100 m²/g. The quantity (weight basis, feed:adsorbent) of the solidadsorbent material used in the embodiments herein is about 0.1:1-20:1,0.1:1-10:1, 1:1-20:1, or 1:1-10:1. In certain embodiment, solidadsorbent material is attapulgus clay and has an average pore size inthe range of from 10 angstroms to 750 angstroms. In a furtherembodiment, solid adsorbent material is activated carbon and has anaverage pore size in the range of from 5 angstroms to 400 angstroms.

Spent solid adsorbent material can include adsorbed heavy polynucleararomatic molecules, compounds containing S, compounds containing N,and/or compounds containing metals and/or metals. In certainembodiments, solid adsorbent material is “spent” when more than 50% ofits original pore volume has been blocked by deposited carbonaceousmaterial and other contaminants. In further embodiments, solid adsorbentmaterial is considered “spent” when less than 50% of its original porevolume has been blocked by deposited carbonaceous material and othercontaminants, for example, 25-49, 25-45, or 25-40%, particularly wherethe partially spent material is intermingled in an asphalt pool.

Suitable stripping solvents include benzene, toluene, xylenes,tetrahydrofuran, methylene chloride. Solvents can be selected based ontheir Hildebrand solubility factors or on the basis of two-dimensionalsolubility factors. The overall Hildebrand solubility parameter is awell-known measure of polarity and has been tabulated for numerouscompounds. (See, for example, Journal of Paint Technology, Vol. 39, No.505, February 1967). The solvents can also be described bytwo-dimensional solubility parameters, that is, the complexingsolubility parameter and the field force solubility parameter. (See, forexample, I. A. Wiehe, Ind. & Eng. Res., 34(1995), 661). The complexingsolubility parameter component which describes the hydrogen bonding andelectron donor-acceptor interactions measures the interaction energythat requires a specific orientation between an atom of one molecule anda second atom of a different molecule. The field force solubilityparameter which describes van der Waal's and dipole interactionsmeasures the interaction energy of the liquid that is not impacted bychanges in the orientation of the molecules.

In certain embodiments the stripping solvent is a non-polar solvent orcombination of solvents have an overall Hildebrand solubility parameterof less than about 8.0 or a complexing solubility parameter of less than0.5 and a field force parameter of less than 7.5. Suitable non-polarsolvents include, for example, saturated aliphatic hydrocarbons such aspentanes, hexanes, heptanes, paraffinic naphthas, C5-C11, keroseneC12-C15, diesel C16-C20, normal and branched paraffins, mixtures of anyof these solvents. In certain embodiments the solvents are C5-C7paraffins and C5-C11 paraffinic naphthas.

In certain embodiments the stripping solvent is a polar solvent orcombination of solvents having an overall solubility parameter greaterthan about 8.5 or a complexing solubility parameter of greater than oneand a field force parameter value greater than 8. Examples of polarsolvents meeting the desired solubility parameter are toluene (8.91),benzene (9.15), xylene (8.85), and tetrahydrofuran (9.52). Suitablepolar solvents include toluene and tetrahydrofuran.

Examples

Example 1—A sample of 100 grams of vacuum residue derived from ArabHeavy crude oil is delayed coked at 499° C. to produce coke, lightgases, (C₁-C₄) and distillates. The properties of feed streams aresummarized in Table 4 and the yields are summarized in Table 5.

Example 2—A sample of 10 grams of hydrocracker bottoms was mixed with 90grams of vacuum residue derived from Arab Heavy crude oil. The mixtureis delayed coked at 499° C. to produce coke, light gases, (C₁-C₄) anddistillates. The properties of feed streams are summarized in Table 4and the yields are summarized in Tables 5 and 6. Table 5 summarizes theresults obtained from calculated MCR content of the samples. Table 6summarizes the results obtained from actual MCR measurement. Thereproducibility of MCR analysis is 0.26 W %. It is apparent that thehydrocracking recycle oil impacts the MCR measurement, which is anindicator for coke formation.

Example 3—A sample of 25 grams of hydrocracker bottoms was mixed with 75grams of vacuum residue derived from Arab Heavy crude oil. The mixtureis delayed coked at 499° C. to produce coke, light gases, (C₁-C₄) anddistillates. The properties of feed streams are summarized in Table 4and the yields are summarized in Tables 5 and 6. Table 5 summarizes theresults obtained from calculated MCR content of the samples. Table 6summarizes the results obtained from actual MCR measurement. Thereproducibility of MCR analysis is 0.26 W %. It is apparent that thehydrocracking recycle oil impacts the MCR measurement, which is anindicator for coke formation.

Example 4—50 grams of hydrocracker bottoms was mixed with 50 grams ofvacuum residue derived from Arab Heavy crude oil. The mixture is delayedcoked at 499° C. to produce coke, light gases, (C₁-C₄) and distillates.The properties of feed streams are summarized in Table 4 and the yieldsare summarized in Tables 5 and 6. Table 5 summarizes the resultsobtained from calculated MCR content of the samples. Table 6 summarizesthe results obtained from actual MCR measurement. The reproducibility ofMCR analysis is 0.26 W %. It is apparent that the hydrocracking recycleoil impacts the MCR measurement, which is an indicator for cokeformation.

Example 5—75 grams of hydrocracker bottoms was mixed with 25 grams ofvacuum residue derived from Arab Heavy crude oil. The mixture is delayedcoked at 499° C. to produce coke, light gases, (C₁-C₄) and distillates.The properties of feed streams are summarized in Table 4 and the yieldsare summarized in Tables 5 and 6. Table 5 summarizes the resultsobtained from calculated MCR content of the samples. Table 6 summarizesthe results obtained from actual MCR measurement. The reproducibility ofMCR analysis is 0.26 W %. It is apparent that the hydrocracking recycleoil impacts the MCR measurement, which is an indicator for cokeformation.

Referring to FIG. 7, the recycle content is plotted against the cokeyield for examples 1-5. As is apparent hydrocracking recycle oil streamminimizes the coke yield. In the presence of hydrocracking recycle oilthe coke yield drops down. This is due to the hydrogen donor effect ofthe recycle oil stream. The hydrocracking recycle oil is rich inhydrogen, 14 W %, and donates hydrogen to stabilize the free radicalsformed during the coking process, thereby minimizing the coke formation.

TABLE 4 Example 1 2 3 4 5 Feedstock Vacuum Residue Recycle Oil BlendBlend Blend Blend VR Content, W % 100 0 90 75 50 25 API Gravity, ° 4.032.1 6.4 10.1 16.7 24.0 SG 1.0440 0.8651 1.0261 0.9993 0.9546 0.9098Carbon Content, W % 83.61 86.00 83.85 84.21 84.81 85.40 Hydrogen, W %10.15 14.00 10.54 11.11 12.08 13.04 S, W % 5.34 0.01 4.81 4.01 2.67 1.34N, W % 0.48 1.00 0.54 0.61 0.74 0.87 Oxygen, W % 0.00 0.00 0.00 0.000.00 CCR (calc), W % 23.05 0.08 20.75 17.31 11.57 5.82 CCR (measured), W% 23.05 0.08 16.96 15.96 10.19 5.54 C5-Asphalthenes, W % 0.05 0.00 0.050.04 0.03 0.01 Ni, ppmw 59 0 53 44 29 15 V, ppmw 176 0 158 132 88 44

TABLE 5 Example 1 2 3 4 5 Recycle Oil 0 10 25 50 75 Vacuum Residue 10090 75 50 25 Coke 36.9 33.2 27.7 18.5 9.3 Gas 11.1 10.8 10.3 9.5 8.6Naphtha 19.2 18.4 17.2 15.3 13.3 Gas Oil 19.2 22.5 27.3 33.9 37.5 VGO13.6 15.1 17.5 22.9 31.3 Total 100.0 100.0 100.0 100.0 100.0

TABLE 6 Example 1 2 3 4 5 Recycle Oil 0 10 25 50 75 Vacuum Residue 10090 75 50 25 Coke 36.9 27.1 25.5 16.3 8.9 Gas 11.1 10.2 10.1 9.3 8.6Naphtha 19.2 17.1 16.8 14.8 13.2 Gas Oil 19.2 27.8 29.0 35.1 37.6 VGO13.6 17.7 18.6 24.6 31.8 Total 100.0 100.0 100.0 100.0 100.0

While not shown, the skilled artisan will understand that additionalequipment, including exchangers, furnaces, pumps, columns, andcompressors to feed the reactors, maintain proper operating conditions,and to separate reaction products, are all part of the systemsdescribed.

The method and system of the present invention have been described aboveand in the attached drawings; however, modifications will be apparent tothose of ordinary skill in the art and the scope of protection for theinvention is to be defined by the claims that follow.

1. A process for separation of heavy poly nuclear aromatic (HPNA)compounds and/or HPNA precursor compounds from a hydrocracker bottomsfraction prior to recycling within a hydrocracking operation, theprocess comprising: subjecting the hydrocracker bottoms fraction tothermal cracking in a coking zone to produce thermally crackedhydrocarbon products and coke, wherein the coke contains HPNA compoundsand/or HPNA precursor compounds from the hydrocracker bottoms fraction;and recycling all or a portion of the thermally cracked hydrocarbonproducts within the hydrocracking operation.
 2. A hydrocracking processcomprising: subjecting a hydrocarbon stream to one or more hydrocrackingstages to produce a hydrocracked effluent; fractionating thehydrocracked effluent to recover one or more hydrocracked productfractions and a hydrocracker bottoms fraction corresponding to thehydrocracked bottoms fraction of claim 1; wherein recycling all or aportion of the thermally cracked hydrocarbon products within thehydrocracking operation comprises recycling all or a portion of thethermally cracked hydrocarbon products to at least one of the one ormore hydrocracking stages.
 3. A two stage hydrocracking processcomprising: subjecting the hydrocarbon stream to a first hydrocrackingstage to produce a first hydrocracked effluent; fractionating the firsthydrocracked effluent to recover one or more hydrocracked productfractions and a hydrocracker bottoms fraction corresponding to thehydrocracked bottoms fraction of claim 1; wherein recycling all or aportion of the thermally cracked hydrocarbon products within thehydrocracking operation comprises passing all or a portion of thethermally cracked hydrocarbon products to at least one of the one ormore hydrocracking stages.
 4. The process as in claim 3, wherein thesecond hydrocracked effluent is fractionated with the first hydrocrackedeffluent.
 5. The process as in claim 1, wherein the coking zone producesa coker liquid and gas stream that is fractioned into one or morestreams forming recycled thermally cracked hydrocarbon products.
 6. Theprocess as in claim 5, wherein the recycled thermally crackedhydrocarbon products are selected from the group consisting of: cokergas oil; coker gas oil and coker middle distillates; and coker gas oil,coker middle distillates and coker naphtha. 7-8. (canceled)
 9. Theprocess as in claim 1, wherein the coking zone is a delayed cokeroperating at a temperature (° C.) in a coking drum of the delayed cokerof about 425-650; a pressure (bars) in the coking drum of about 1-20;and a steam introduction rate of about 0.1-3 wt % relative to the heatedresidue.
 10. (canceled)
 11. The process as in claim 1, wherein thecoking zone is a fluid coker operating a temperature (° C.) in a cokingdrums of the fluid coker of about 450-760; a pressure (bars) in thecoking drum of about 1-20; and a steam introduction rate of about 0.1-3wt % relative to the heated residue.
 12. (canceled)
 13. The process asin claim 1, wherein adsorbent material or catalytic material is added tothe coking zone.
 14. The process as in claim 13, wherein catalyticmaterial is added, and wherein catalytic material is a heterogeneouscatalyst selected from the group consisting of silica, alumina,silica-alumina, titania-silica, molecular sieves, silica gel, activatedcarbon, activated alumina, silica-alumina gel, zinc oxide, clays, freshcatalyst materials, used catalyst materials, regenerated catalystmaterials and combinations thereof.
 15. The process as in claim 14,wherein the heterogeneous catalyst incudes one or more active metalcomponents of metals or metal compounds selected from the Periodic Tableof the Elements IUPAC Groups 4, 5, 6, 7, 8, 9 and
 10. 16. The process asin claim 15, wherein the active metal component is a metal or metalcompound selected from the group consisting of Mo, V, W, Cr, Fe andcombinations thereof.
 17. The process as in claim 16 wherein the activemetal component is a metal or metal compound selected from the groupconsisting of vanadium pentoxide, molybdenum alicyclic and aliphaticcarboxylic acids, molybdenum naphthenate, nickel 2-ethylhexanoate, ironpentacarbonyl, molybdenum 2-ethyl hexanoate, molybdenumdi-thiocarboxylate, nickel naphthenate, iron naphthenate andcombinations thereof.
 18. The process as in claim 13, wherein catalyticmaterial is added, and wherein catalytic material is a homogeneouscatalyst that is oil-soluble and contains one or more active metalcomponents of metals or metal compounds selected from the Periodic Tableof the Elements IUPAC Groups 4, 5, 6, 7, 8, 9 and
 10. 19. The process asin 18 wherein the homogeneous catalyst is, or contains as an activemetal component, a transition metal-based compound derived from anorganic acid salt or an organo-metal compound containing Mo, V, W, Cr,Fe and combinations thereof.
 20. The process as in 18 wherein thehomogeneous catalyst is, or contains as an active metal compound, acompounds selected from the group consisting of vanadium pentoxide,molybdenum alicyclic and aliphatic carboxylic acids, molybdenumnaphthenate, nickel 2-ethylhexanoate, iron pentacarbonyl, molybdenum2-ethyl hexanoate, molybdenum di-thiocarboxylate, nickel naphthenate,iron naphthenate and combinations thereof.
 21. The process as in claim13, wherein adsorbent material is added, and wherein adsorbent materialis selected from the group consisting of silica, alumina,silica-alumina, titania-silica, molecular sieves, silica gel, activatedcarbon, activated alumina, silica-alumina gel, zinc oxide, clays, freshcatalyst materials, spent catalyst materials, regenerated catalystmaterials, and combinations thereof.
 22. The process as in claim 1,further comprising introducing additional feed to the coking zone. 23.The process as in claim 22, wherein the additional feed is selected fromthe group consisting of atmospheric residue, vacuum residue, deasphaltedoil and demetallized oil.
 24. The process as in claim 22, wherein theadditional feed comprises 10-99 wt % of total feed to the coking zone.25. (canceled)
 26. The process as in claim 22, further comprisingsubjecting the additional feedstock to residue hydrocracking prior tointroducing to the coking zone.
 27. The process as in claim 22, furthercomprising subjecting the additional feedstock to solvent deasphaltingprior to introducing to the coking zone.
 28. (canceled)
 29. The processas in claim 22, further comprising subjecting the additional feedstockto oxidation prior to introducing to the coking zone.
 30. The process asin claim 22, further comprising contacting the additional feedstock withadsorbent material prior to introducing to the coking zone.
 31. A systemfor removal of heavy poly nuclear aromatic (HPNA) compounds and/or HPNAprecursor compounds from a hydrocracker bottoms fraction comprising: acoking reaction and separation zone having one or more inlets in fluidcommunication with a hydrocracker bottoms outlet of a hydrocrackingfractionating zone, and one or more outlets for discharging thermallycracked hydrocarbon products in fluid communication with a hydrocrackingoperation as a bottoms recycle stream, and one or more outlets for cokecontaining HPNA compounds and/or HPNA precursor compounds from thehydrocracker bottoms fraction. 32-34. (canceled)